Kinder Morgan, Inc. (KMI) Q3 2016 Earnings Report, Transcript and Summary

Thank you for standing by and welcome to the Quarterly Earnings Conference Call. All participants will be in a listen-only mode, until the question-and-answer portion of today’s conference. [Operator Instructions] Today’s conference is being recorded. If you have any objections, you may disconnect at this time. Now, I would like to turn the call over to Mr. Rich Kinder, Executive Chairman of 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 industry wide in nature and the other specific to KMI. Let’s start with the industry wise 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 growth projects. Fossil fuels, and especially natural gas which has now surpassed coal as the primary fuel source for prior generation in the U.S. 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 protestors 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 is a big difference for example between state permitted projects where eminent domain is a function of state law and the federally certificated natural gas project. Ultimately we realize that the environment is changing and we are adapting by building those changing circumstances into how we budget and plan our projects. Now to the comment specific to Kinder Morgan. During the third quarter, we substantially reduced our debt and this positions us for long term value creation. We are now ahead of our plan for 2016 year end leverage and as the Chairman and largest shareholder of the company I am very pleased with the progress we are making towards achieving our target leverage level of around five 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 towards increasing the dividend substantially while maintaining both greater coverage than in the past and a stronger balance sheet. That said, we’ll obviously make the best economic decision at the time we reach that point and 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. And with that, I’ll turn it over to Steve.

Good day, thanks Rich. So I’ll 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 we’ll start with the fundamentals. We consistently hear from producers in Canada and some refiners in the Northwest U.S. that they are counting on this project to get build. Production is expected to continue growing even though it’s at a slower rate on the oil sands and take away 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 are 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 undertaken 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 are actively engaged with the BC government on the satisfaction of their five conditions. Finally I’ll note that we do believe that this project would make a very good candidate for brining 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 view processes that are nearing a conclusion now they following those reviews assuming the outcomes are favorable or if the outcomes are favorable we would look to syndicate this investment. We’ve got a lot of options here including self funding so we are not committing to any one approach but we do think it’s 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 as the authorization follows the 7C that takes our implementation plan, it gives us permission to go forward with this structure. So we and Shell our customers are prepared for us to begin construction starting the first of November. With respect to the rest of our projects, we have been docking for several quarters now about high grading the backlog that’s making sure that we are 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’s down from $13.5 billion last quarter. We believe it’s 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 to the 13, we put $600 million worth of projects into service during the quarter including bringing on intrastate Texas gas crossover project that’s in support of LNG and Mexico market. Taking delivery of two Jones Act vessels which are under charter, completing two smaller liquids terminal expansions and we completed the 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. A $130 million of that in gas and $75 million in CO2 where we continue to see good returns even in current prices. If you look at the year-to-date numbers we’ve added a little under $600 million dollars about $575 million in new projects, now that’s been - the backlog has been coming down, so that’s been more than -- those editions have been more than offset by projects that’s going into service and project cancellations earlier in the year. But overall I think what this shows you is we’ve been successful in doing what we set out to do. We have high graded the backlog to strengthen our balance sheet and enable the funding of our growth projects without needing to access capital markets while continuing to add projects where we find them at attractive returns. Now 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 etcetera and we’ve seen some stabilization in counter party 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 now track with us, so no impact from customer defaults in the third quarter. So now turning to the segment for some highlight 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 $350 million dollar non-cash impairment on our MEP investment driven by the expectation of future lower contract rates and approximately $84 million loss associated with partial sale of S&G. If you look at segment earnings before DD&A and 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 lower prices $62 barrel realized versus $74 in the third quarter of last year and lower production. Nevertheless we expect CO2 to make plan due to some price improvement versus our plan price and good performance on cost savings for that segment. Compared to the same quarter last year, gas is down 2%, while terminals and products 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 are benefitting 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 to 7 Bcf this quarter. On a macro basis, [gases] now we are taking 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 the 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 are 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 [Indiscernible]. 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 systems to more of Marcellus and Utica gas to the south. Natural gas which is by far our largest sector is kind of 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 and overall this business outside of the take or pay commitments that we have is dependent on the recovery in those phases as gas demand grows and oil prices and therefore drilling recovers. We continue to believe that the need for natural gas transportation storage capacity will grow as demand trends that I talked about continue and in the longer term the gathering volume flatten and turn up when we ultimately see recovery in the gas supply basis that we serve. In products pipelines we are getting the benefit year-over-year of higher volumes. Refined products volumes are up 3% quarter-to-quarter, 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 turn around by one of our customers. In terminals we are seeing the benefit of new liquids capacity coming online and increased utilization of that expanded capacity, so more capacity on line 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 business is over 75% of the segment earnings before DD&A, before certain items and the increased utilization we are seeing and the expansions we are 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 with a 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 till the overall U.S. fleet is right sized from the capacity standpoint. At the bulk side we are down slightly year-over-year primarily again attributable to the coal business. In CO2 we have 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 of the segment a record quarter impact which is slightly higher than last year. And we also approved some new EOR development projects during the quarter and continue to find attractive return projects in this segment. And with that I’ll turn it over to Kim for the financials.

Okay, thanks, Steve. Today we are declaring a dividend of $0.125 per share consistent with our budget and the guidance we gave here 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 revenues 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 and sporadic accounting entries for certain items, the largest impact of the certain items on changes and revenues and cost of sales relates to the unrealized CO2 mark-to-market and hedge and effectiveness 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’s driving that loss. We recorded a $230 million non-cash after tax and that’s why that number is a little different from what Steve said, because this is after tax impairment on our MEP investment driven by 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 and how we can have such a large book tax expense on a relatively modest book loss when you had ordinarily expect a book tax benefit, I would be happy to explain later that 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 and certain items for the quarter, so net income before certain items was a positive $343 million. The adjusted number in 2015 of was $345 million or down $2 million essentially flat. EPS excluding certain items was $0.15 or down $0.01 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 and the earnings release. DCF is the primary financial measure on which management judges its performance. We generated total DCF for the quarter of $1.05 billion versus $1.095 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%. And as our previously mentioned CO2 decreased $53 million and natural gas decreased about $18 million which offset 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 terminal segments. 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 1st of this year. Adding back an $11 million change in JV DD&A, which primary reflects our increased interest in GPL that we acquired in the fourth quarter of 2015 and we add that back to the segments, the segments down $33 million. The assets are really down about $22 million. This $22 million decrease was partially offset by $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 utilizes NOLs in 2015 is largely offset by an $18 million decrease in sustaining CapEx a lot of which is cost savings. Netting up the $39million increase in preferred stock dividends gets 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 $0.01 due to the additional shares that were issued during 2015 to finance our growth projects to maintain our balance sheet. $0.48 in DCF per share results in $801 million in excess distributable cash flow above our $0.125 dividend for the quarter. And year-to-date we have generated approximately $2.5 billion of excess distributable cash flow above our dividend. Now let me give you some details on our expected performance for the full year versus budget. Natural gas pipelines is 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 and service as a result of a delay in receiving our FERC certificate. If you exclude the impact of a 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’s a 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 budgeted. Actually throughput on our liquids terminals year-to-year when you compare it to 2015 is actually it’s 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 loss 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 are expecting to come in lower than budget or said in other way they are expected to be a favorable variance, primarily as a result of lower interest in sustaining CapEx. Interest is expected to be approximately 4% below its budget; about half of this variance or over half of this variance is associated with the 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 excluded the impact from the 50% sale of SNG. We continue to expect that adjusted EBTIDA 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, though 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 to the lost SNG EBITDA as we use all the proceeds from this transaction to reduce debt. And the second point is that we expect in the year a 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'll move to the balance sheet. When you look at total assets on the balance sheet, total assets are down $2.5 billion and that's 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 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's where we would expect to in the year. And 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've generated DCF of $1.08 billion. We spend about $550 million in expansion CapEx acquisitions and contributions to equity investments. We paid $280 million in dividends. We have 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 $8.3 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 use that to pay debt on October 1st, so that debt was not [paid down as of 9/30], but has subsequently been paid down. And 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've generated DCF of $3.36 billion. We had expansions, acquisitions and contributions to equity investments of $2.43 billion. 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 on restricted cash or other current assets on our balance sheet. Again the paid down, we use to pay down debt on October the 1st, and then we had working capital and other items that was use of cash of about $168 million. And that gets you to the $1.976 billion reduction in debt. So with that, I'll turn it back over to Rich.

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

Thank you. We will now begin the question and answer portion. [Operator Instructions] Our first question is from Kristina Kazarian from Deutsche Bank. Your line is now open.

Afternoon, guys. Steve appreciated the projects updates. A couple of quick clarifications; on Utopia any color on the judges denial of your use of eminent domain and maybe could you talk about what this means for that projects? And then on Elba, appreciate the November 1st date, but can you just remind me. Am I still going through that hearing process and what does that mean for that project going forward?

Okay. I'll start with Utopia. We had Wood County judge who interpreting the eminent domain statute, interpreted that our pipeline didn't qualify for eminent domain. We're feeling that in fact we file the appeal last week, it’s been consistent with other decisions including appellate decisions that have been made in the state, so we think we'll ultimately going to prevail on appeal there. There maybe some other decisions that come out of Wood County they will be consistent with that, but we expect to ultimately to prevail on appeal. Now we are going to - we are in the process of evaluating what that means. We're two-thirds of the way through acquiring right way already separate apart from what happened with that decision. So, now 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 what are legal strategy is going to be et cetera, but that what that decision about, that's where we are in the project in terms of acquiring right-of-way what we plan to do in term of what we've already done in term of appeal. On the Elba projects, yes, we have - we've reach agreement with Shell to proceed without the rehearing having been finalized. So, we're ready to go. Our customers ready to go, we're ready to go, we have our 7C 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 of the hearing. So we are proceeding and starting up November 1.

Perfect. Thanks. And then just a quick follow-up from me too, Rich mentioned the change in regulatory headwinds. Do you think there is a possibility for a change intact to the positive here, what could be a driver for that? And if we don't make a change what could be some other 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. So we have to make the appropriate adjustments. In terms of what can turn that around. Again, this varies from place to place. I mean we built our Texas pipeline over the summer effectively and you have to go kind of place by place and kind of commodity by commodity to just sort this out, but the bottom is if 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. So, it’s not that the whole world need to change, this is a kind of 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 can already, it’s been a big part of the answer to reduce CO2 emissions and cleaner power generation and compliance with the clean power plant 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.

Welcome.

Next question is from Jeremy Tonet from JPMorgan. Your line is now open.

Hi, Jeremy.

Kindly check you mute function Mr. Tonet. We'll move to next question and that is from Ms. Christine Cho from Barclays. Your line is now open.

Hi, everyone. 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 or even talks with parties and just waiting for that. Or have talks sort of curb now just because it's not as urgent with, but which coming in better than your target for year end?

Yes. Christine, we've talked and we put Elba in as a placeholder kind of where we showed everyone our capital expenditure plans and everything at the beginning of the year. Placeholder as JV we don't have the JV Elba. I think it is a very amendable to a joint venture. It is a standalone asset investment at least when it comes to liquefaction facilities and it's attractive. It's under a 20 years contract for Shell. We've got the ability to sell fund that or JV it, but it is an attractive JV candidate, but again we're not in a position where we have to do anything and particular with it. But we continue to explore option to JV assets and that's one of the big variables and sort of 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 mean I think in the context of FERC 7C it is often, it's traditional for you get the 7C 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 reason, extremely thorough 7C. They took extra time to get it out and so we think it's going to withstand any rehearing or appeal and so we're going to go ahead and get started.

Okay, great. That was helpful. And 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're open to JVs, but how do you guys think about project financing this project? Or what terms that usually come with project financing immediately rule that out, and by terms I mean anything that would restrict how cash you could pay out from the asset. Just curious as to how you think about that option?

Well, I think we'll 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 be the JV candidate and what's the timing of it going forward and then we'll 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 you would being towards having the assets kind of the off balance sheet or that's kind of [Indiscernible]?

If you're asking -- I think that the way -- we would look at it both ways. Having the leverage on our balance sheet and not having 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 from 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. I'm just curious as to what your view on the landscape is for M&A in the U.S 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 new infrastructure like you said earlier Rich, or do you think it’s just more fact specific?

I think it’s always pretty fact specific or situation specific. We continue to look for the opportunities, but in addition to being accretive to DCF they kind of need to be accretive to leverage metrics, they still have to work for that standpoint. So, it’s a little more difficult to get through the screens, but I think ultimately there's going to be consolidation in this sector. If 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.

Next question is from Mr. Brian Gamble from Simmons & Company. Your line is now open.

Good afternoon, Brian.

Good afternoon Rich. How you're doing?

Good.

Kind of maybe just follow-up on the M&A discussion while we've got it, I think is a tough one to get through, lots of moving pieces with any combination that may try to put together, but when you think about individual assets. And Steve you mentioned essentially the deleveraging events, given the assets that you guys have in place today. Are there assets that if they were deleveraging events in totality you would consider divesting them, and of course I'm speaking specifically about CO2, but it’s getting something north of the deleverage multiple enough to make an asset that didn't quite score to your competencies, sellable items?

There are unique considerations that surround everyone. As we've shown making progress this year on our leverage metrics, we've considered non-core asset sales. We had a few of those and the big transaction of course with SNG and that was the bit unique circumstances, we're not generally in the business of selling cash flow in pipeline asset. But in that particular case we had partner who is bring value, securing the assets, but also bringing incremental investment opportunities to project, so made a lot of sense for us to ahead and do that. With respect to CO2 specifically we like that business. It’s a good business. We invest and get good returns on that business. It’s a niche for us. We're not out chasing E&P and Shell and offshore and things like that. We have CO2 which is a scares commodity and we have the infrastructure to get it delivered to EOR fields where it’s the only thing that can free up oil. And we've integrated forward into enhance all recovery and we've got expertise there. We think we're good at it. So we like that business and we're happy to keep running it. If you think about new question in terms of transaction or 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 considered and do it if it make sense. The considerations around CO2 specifically is that it would probably 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 yield contraction on DCF that you get by having a better portfolio or a more stable portfolio of remaining businesses enough to offset that introduce real shareholder value. And certainly there are theoretical numbers at which that would work. And so again we're 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 assets that make it a more, I guess, make the hurdle easier to jump over knowing that shareholder 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 would the dilution be and what would our multiple increase need to be more than offset that, so at the other side of it a shareholder is better off. That's the calculation we make.

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

I think we've always said, we wanted to get to around five times before we increase the dividend and that's still our target. But again I think it's important that we've got so many questions about this. We elected to layout a little bit detail on and our game plan again we would reserve the right to see what the facts on the ground or when we get to that point, but our game plan would be we obviously have a lot of fire power, lot of free cash flow and to the extent we can substantially increase the dividend while still [maintaining an average] 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 things going through book constrictor like Trans Mountain for example. You are kind of in that, I don't know, two, two and a half, 3 billion in that range and if you say once our balance sheet is where we want and we're going to finance half of that out of retaining cash and half of that back in the debt market at that point in time than you can get, you can see your way clear to having a very nice dividend but with very nice coverage and maintaining a strong balance and that's really the prime factor that we're looking for and I think, I mean, just look at this year and I think Kim emphasize this year, we're right consistent ebbs on the SNG transaction where we told you in April and where we told you in July was going to be and at least the DCF of about $2 per share for this year and we're paying out $0.50 dividend and that's well 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 like to cover our portion, the equity portion of the normalized CapEx program.

Appreciate the color, Rich.

Our next is from Brandon Blossman from Tudor, Pickering. Your line is now open.

Hello, Brandon.

Good afternoon everyone. I guess let's start with Trans Mountain again. Steve you are 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 cause you to be clearer about that messaging, was it counterparty interest or has this been kind of the plan all along?

Well, I think it’s - we talked about it and answer to a question I think on the last call, so it’s consistent within to that point, but we're getting closer now to some - to decision point and resolution and yes, there's been interest in the project if you would expect, and so it just a kind of a as I said a little bit of ripening here from -- ripening in the process and our thinking there's a little ripening left to go in terms of getting some of these, getting the clarity on the regulatory fund which again appears to be getting closer.

Okay. Probably as expected the project screens are - almost screens for a JV partner here. As you think about in kind of prioritize or rank potential partners and project promotes back 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 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 kind of return to getting cash back to shareholders. How do you balance all those pieces with that equation conceptually?

Those are all three benefits, right, and agree with those, but we're really not for closing, we've got a lot of options in addition to having a good interest and we 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 noting the potential there and the opportunity that create more value near term rather than longer term. Okay, I'll leave that one to rest. Another broad question, surprises about 12 months ago from the rating agencies, how was those conversations kind of 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.

I mean, if you think about where we were 12 months ago, 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're 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 from me. The MEP writedown, what triggers that process or that consideration?

Yes. We just had some interest from various shippers and potentially working at contracts, when 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 current that we have - we have that asset.

All right, great. Understood. Thank you very much.

Next question is from Jean Ann Salisbury from Bernstein. Your line is now open.

Good evening. Just a couple of quick ones from me, so we've had nice run in crude price recently and services costs have come down a lot this year. At this new lower service cost can you give a range of oil price at which you would be able to book new crude reserve at a level that approximates replacing production and I assume that numbers actually gotten much better from last year?

[Jesse], do you want to add.

Yes, I think we add these projects throughout the year, so as price has improved, I would say, we're adding reserves today.

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

Yes. I mean, we don't look at it that way. The way we look at it is look at a discrete project by project and we look after returns on the project that this year two groups bring forward, and if those returns clear our hurdle and the minimum amount of that hurdle 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 than generally we are not pursuing those projects.

Okay. Understand. Thank you. And then my second question, exports to Mexico as you guys have noted have grown massively 3.3 Bcfd, I believe that you mentioned that the majority of that moves on Kinder Morgan pipeline. There are punch of new Mexico export pipes I think 3 Bcfd coming on in the first half of next year. Will that have a material impact on your fiscal flow of the segment EBITDA?

I think that a 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 NET pipeline that were in the service 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 the 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 polling into Mexico that's happening increasing volumes over the year. So even if it’s not us constructing in country place which we haven't gotten comfortable with from a risk rewards standpoint, the increase in demand and hooking it up, increasingly to U.S. supply sources is going to benefit our system overall, transport as well as storage and on the intrastate side sales.

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

Thanks. That's very helpful. And then, lastly are we close contracts minimum on gas gathering, so another thing is Eagle ford production continues to decline, there actually won't be much impact on Kinder Morgan?

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

Okay, great. Thanks. That's it from me.

Next question is from Danilo Juvane from BMO Capital Markets. Your line is now open.

Thank you. Most of my questions have been hit. I did have one very quick follow-up on the Eagle Ford's volume - 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 suppose to be imminent here, was that something they expect to sort of be reflected in your volumes over time?

Yes. 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. And so we have if you will restore 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 decline is [still calm], but I think that the program that Tom and his team initiated was successful in taking our market share backup.

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

We have other pipes that are kind of what you call bases pipeline, FEP is another example and so pipes that are kind of point to point that had long term contracts that under wrote them when there were expanded as those contract roll off and bases has come in that would present the same kind of phenomenon.

Do you guys have sort of magnitude of what the revenue impact or EBITDA impact would be going forward here?

Well the FEP is not revenue issue in terms of what's 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 had a non-cash impairment on those assets. So the customers are still paying in fact the largest customer on FEP is South Western, I think they've actually put a rigor to back into the pay a bill and their credit situation I think has improved dramatically over the last few months.

Thanks for the color. Last question from 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, 250, yes, 250.

Okay. Thank you. That's it from me.

Next question is from Ted Durbin from Goldman Sachs. Your line is now open.

Hi, Ted. How you're doing?

Doing well. Thanks, Rich. Coming back to Trans Mountain here, so maybe you can give us a little bit of preview on this ministerial penals report, I think it’s due November 1st and kind of how that will impact the December decision and then also an update on the BC process meeting the five conditions and particular I think revenue showing one of the big ones there?

Yes. So there were couple of if you will additional federal processes, one was federal consultation process where the federal government was directly out consulting with first nations and communities. The one that you were specifically referring to was there was a three - 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 NED proceeding. That process is wrapped up in terms of the hearing and as you pointed out there is a report that's due. It’s a report that is cataloguing at least as I understand it, everything that the group of three heard while they were talking to people and 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 schedule for December 20th. So I don't know if anything Ted that inconsistent with the December 20th, certainly nothing that associated with those two processes. We still expect to see on or before December 20th, final order in council.

And then my other part of my question, that is a long one on the British Columbia process meeting the five conditions in their revenue sharing?

We have been engaged with British Columbia on the five conditions. I think it's 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 are assuming that is in January - that that is not going to be in December, that that is going to be in January. And so I think what we are aiming for is to have the British Colombia 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 so the project return is still inline what you had originally budgeted?

Project returns are still inline. We are still working on the costs with the contractors. We have made very good progress I would say, but we are not final yet and we are still a complicated project. There is still work to be done there but I think we have made good progress.

Okay. I will leave it at that. Thank you.

The next question is from Shneur Gershuni from UBS. Your line is open.

Good afternoon guys.

Hi Shneur.

I just wanted to confirm your response to one of the earlier questions, I think it was Brian’s question about retain distributable cash flow, I just want to make sure I understood it correctly, let us say you are at a run rate of just using random numbers here $4.5 million in distributable cash flow, and I think if I heard you correctly you talked about potentially holding back about $2 billion of that retained DCF to fund the equity portion of kind of normalized growth CapEx budget?

. : So it is not the whole thing because once we get to the level - the appropriate level of debt we would intend to go back to financing half equity, half debt, but the difference is we would not put - we would not contemplate putting out new equity. We would be using retained cash flow from operations to fund the “equity” portion of that. Does that answer your question now?

Yes, I think we are actually on the same page. So if I do my math correctly, I mean that 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 corresponds with your well of a difference comment earlier?

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

Okay. The second question, I know that you have been asked this many different ways, but I realize the company has made considerable progress of getting down to your stated goal of 5x net debt to EBITDA. I guess kind of two questions in one here, but 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 the 5x leverage goal either through equity or preferred issuances, or even asset sales, or is the board comfortable with the pace where you are at and you will get there when you expect to get there?

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. And so, I think the debt market has changed, the equity market is still significantly different from where we were 12 months ago, 18 months ago. And 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 are doing is we are living within our cash flow meaning that we want to be able to fund our equity - our CapEx apex and our dividend from our cash flow. And so that is the constraint and so because we have limited amount of capital that is why we have the hurdle rate set at 15% unlevered after-tax for project. I fully anticipate that over time as the CapEx ex 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 hurdle rate, but we would have to make the assessment when that time comes.

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

Well, if you mean issuing equity, we are not an equity issuer at these prices.

And that was why that we are living within cash flow given where the current equity prices are.

But look, we are going as fast as we can. If we can find ways to go faster we will. And we are working on this all the time as you might imagine. But it is 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 coalprices recently and I know you have had some challenges at your terminals over the last two years, has there been any increase or increase in terms of folks wanting to ship out coal in bulk out of the U.S. 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% up tick last quarter in our coal volumes mostly on the export side. On a U.S. basis, exports were down 11.8%. That is just a drop in the bucket. We are still down 30% on a year-over-year basis. The prices - we have seen some price compression, margins 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 is not projected a lot higher than that.

So you have got some ground to make up?

Yes.

All right. Thank you very much guys.

The next question is from Darren Horowitz from Raymond James. Your line is now open.

Hi Darren, how are you?

I am fine. 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 marketed pipe capacity versus what you said you expect in Marcellus and your production growth expectations to be, do you think it is a rescaling of marketed pipe or a combination of pipes, and I am most interested to know your thoughts on maybe some basis differential expectations, more pressure in the 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 is 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 [any deal], which we talked about in the first quarter and discontinued, but also with recent rulings that verified that decision. It is making it harder to get things done on kind of a megascale. Now we have continued to engage with our customers on smaller scale projects and will continue to pursue those. But I think from the perspective of right now today it is hard to get new significant gas infrastructure built into New England and now with the intent to increase the basis differentials between what is already the lowest priced gas, dominion south, call it, and the New England market which is 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 is 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 the existing network more valuable. The other thing I would add and let Tom throw in 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. I mean it is 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 are building on our existing footprint that again goes to the need to make distinctions between projects out there and infrastructure projects, building off of our existing footprint, adding compression, maybe laying some parallel pipe, things like that that created 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 bases widen to New England to the northeast, and I think we will find plenty of things to invest in [Indiscernible] plenty of things to invest in on TGP to get that gas someplace else.

Thank you.

Our next question is from Jeremy Tonet from JPMC. Your line is now open.

Okay. You are 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 are talking about the JV here, is this just the extension or the extension of the existing pipe, I guess what it comes back to is when I am thinking - trying to model 5x debt to EBITDA, the spend on TMX and the drag associated with when the cash flow materialize is a pretty big variable in that equation. So I am just wondering if you could help me think through that.

Okay, there are a number of things in there, but I think yes the project is hard to separate from the underlying assets to answer the simplest one of your questions there. On the -- on the approach on what the ownership percentage would be and more of the details I'll go back to the earlier answer, which is we have a lot of options and we're going to pursue the most valuable ones, that’s the easiest way I can characterize it. And we don't have to do anything which is a great position to be in, but we are going to evaluate it.

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

Yes 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.

Next question is from Craig Shere from Tuohy Brothers. Your line is open.

Good afternoon.

Good afternoon. Thanks for taking the extended call here. So a couple of questions here, one, you know Rich, you commented about the historical you know annual run rate call it about $2.5 billion a year, I know we have some take in the Python issues with Trans Mountain and other such items that may be JV, but I guess 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 that really filled 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 call at this time, and against a preliminary outlook as I stress, but that annual burn rate if you will of expansion CapEx is something in the range we talked about. And that's what -- what we would want to use as providing enough coverage we made for the “equity portion” of that burn rate, and I think that almost stationary or that leaves a lot of many to pay dividends but we just look at the exact circumstances when we reach that point.

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

No, 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's something that our business units think makes sense, we got a good customer, good counter party credit, long-term contracts confidence around execution center. We want to -- we want to bring it in to talk about it and we continue to see those come forward. I think, the one place that we took a closer look again with CO2 and we -- 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 look is there something, or there are some things that we might have been able to do if we were in an 8% world that we're not doing when we were 15% world, then yes maybe so, but I think well what we're talking about in the longer term is a return hurdles that we will relax off of the 15% as Kim said, and I think given the network that we have will still find those opportunities off our network and we're finding some of them still today.

Understood. And on MEP, was there some specific kind of ongoing revenue or EBITDAS drag or reduction expected apart from the one-time non cash right down.

If 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 Steven and any more color you can provide there and your comments about the size or duration of the moves. I think you still have American liberty and American pride, you have the contracts, is that correct? And any update about charters rolling over the next couple of years?

Yes, we have two ships that are not yet constructed and those are the only two of the 14 that are currently not chartered. They are the only two of the 16, and they are not currently charted, everything else is -- that there's one that's under a shorter term charter that’s rolling into a long term charter. Everything is chartered; we do have some coming up in one or two in 2017, three in 2017.

And we had a real strong year there, we are up $12 million on the base, mostly due to less off higher and higher rates and then the expansions are another $25.7 million. If you look kind of going forward the risk really is we got $11 million that are under long-term agreement and then $5 million that could be impacted at some point or another, remember it's about 15% of the total earnings for that -- for that group.

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

There's good strong super into something outside of the current shippers. And so yes we still -- 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 they're strong enough, there is strong shipper interests outside of the existing shippers.

Great. And then last question from me, it's kind of a bigger picture, but -- but the -- the [industry don't] want to call it industry, the activism out there that's made it difficult to put on new projects has also started impacting existing projects and that is called into question, what kind of ongoing cost there 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 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.

Next question is from Becca Followill from U.S. Capital Advisors. Your line is now open.

Afternoon, Becca

Afternoon. Three questions for you, one on Utopia back to back. Do you have a timing on the appeals? And, and how many counties have you sued the land owners?

A timing on the appeal, we've asked for an expedited appeal, so we're waiting to see if that’s granted and then they would 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 of the number of counties where we've got [Indiscernible] suits its probably, nearly every county on the …

Several of the counties. And we’ve as is typical all of our projects we tried to avoid use of eminent domain, we negotiate with respect with landowners and as Steve and Rich indicated we’re about 65% just through gaming these months without any eminent domain. So we continue to work that effort while we feel this one County effort, and what happens in other counties, well that remains to be seen.

Well the other judges of course have ruled the other way off…

Well there have been counties that [have ruled] the opposite direction?

Yes.

In Ohio.

Yes, yes.

And including at the appellate level.

With the appellate level on, was that on surveying, or was on eminent domain?

It was an eminent domain.

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

No, it's a county-by-county. This is a county, the county court system, state county court system in each county and then there are appellate districts in the ultimately the Ohio Supreme Court.

But you are appealing through a district court?

We're appealing to a court of appeals.

But do you know which district?

I don’t know what the number is.

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

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

So that would also be in January then?

It’s the sixth that Ron informs me, it’s the six district court of appeals.

Okay

Going back, what was your other questions Becca on…

It would be January, also timing.

First quarter, let’s say first quarter.

Okay. And then finally on Yates, seemed like a fairly big sequential pick down and production there, was there anything unusual that was going on?

Yes, couple of things. We deferred a couple of projects earlier in the year and then we had a power outage in the quarters that significantly attracted fields so, nothing major be honest as…

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

I have to get back to you on that.

Okay. Great. Thank you guys.

Next question is from Chris Sighinolfi from Jefferies. Your line is open.

Good afternoon.

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

Well the original budget was $574 and will be within 4% of that number.

Of that number, okay.

4% percent better in other words….

Better, less.

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 larger magnitude, so I'll follow up maybe with David about what this table represents, but I just want to clarify for our model what the number should be. I guess 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 of where you stand?

Sure, on that on the hedges and this is 2017, we've got and I'm going to give you barrels now because I think that is easier for everybody's models and giving you percentages. And so on barrels we've got twenty-four thousand four hundred barrels hedged for 2017, 13,700 for 2018, 6100 for 2019 and 2300 for 2020. And the 17 barrels that I just gave you include roughly seventeen hundred barrels of NGLs and to give you the prices that go along with that 2017 at $62, 2018 is $66, 2019 is $58 and 2020 is $51.

Perfect. Super helpful.

And the prices include the NGL volumes.

Right, right okay. And I guess the final question from me Kim is just a lot of questions on TMX, obviously appreciate the color on the project procedural past potential for partners. I just, I guess as it relates to your historical cadence around guidance, just given that that's normally early December and a lot of this seems like it will be decided either late December, early 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 of the first quarter.

Yes, precisely yes.

Yes, so we haven't even started reviving [indiscernible] going through our budget process for 2017. And so we normally decide if, when and how to guide when we are deeper it -- will actually when we are completed with that process. So don't have an answer for you yet Chris.

Okay. Well thanks for all the time guys.

Thanks.

I’m sorry. Next question is from Faisel Khan from Citigroup. Your line is open.

Hi, Faisel how are you this afternoon.

Hi, okay thanks good evening. In terms of the TMX again, can 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'll be stuff being negotiated with 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 contributions let's talk about the quarter from the Highland mid to Highland Midstream assets. What exactly is that associated with, was that associated with higher volumes or if there's something else going on there on the midstream…..

No it was shifting contracts from commodity sensitive contract structures where you know we were getting a percentage of proceeds to locking in the fee and giving the producer the commodity upside. And 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 in this quarter.

Yes. Really through for the year too.

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

We are within our hedging program.

Okay. And the tax expense you talked about for SMG, is that just related to the deferred tax assets of the entire companies 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 non-deductible goodwill.

Okay, okay that makes sense. Okay, it’s all I had guys. Thanks.

Next question is from John Edwards from Credit Suisse. Your line is now open.

Hey, Jonathan, how are you doing?

I’m doing good. I'll try to keep this really brief. Just can you remind us on Trans Mountain, what that CapEx cap is? And then if you can remind us how much arm you've invested in Trans Mount to date?

It's a $6.8 billion is the Canadian -- is the is the capital amount. And by the end of the year it will be a little under $600 million invested, but keep in mind that there's a Canadian yes, and keep in mind that we -- 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 isn't all matchup in time. That's extended over a 10-year period, but $250 million with the development costs is funded through the firm 50 fees.

And then beyond that is of course we have explained before, we have commitments from the shippers for a portion of this in the event that the project would not go far, so it's not like all of this is on our [indiscernible] I think Steve's explained that the past.

Okay, so if it doesn't go forward, approximately what percentage basically you have been….

Varies, depending on the reason, but it's generally no less than 80% is borne by the shippers.

Okay, that's helpful. And then the December 20th, is that 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's going to have additional conditions or affirm the [NAVs] existing 157 conditions or so. So it's not a -- 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 pop the project is being in the public convenience and necessity so it will be definitive from that standpoint, we would expect plus there’s something very different here. We’d expect them to make that determination definitively.

Okay, so that that becomes effectively the go/no go is this public…

I’m not clear what you mean by go/no-go…

I mean, I mean like you get a decision, I mean does that mean your face for example they did not find it's in the public convene, 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 as a public convenience and necessity, but they have some conditions, I'm presuming them, the project for all practical purposes definitely goes forward that's what I'm just trying to figure out.

Yes and 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 community communications all of which we expect to happen fairly shortly after the federal order. The federal order could be a range of things, I mean naturally we think we made a very good case, and we've -- 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 will find it determination that it is in the public convenience and necessity, but it could also have additional conditions and we'd have to examine what those conditions are and what impact they have on the project. And to your point, yes they could determine that it's not and that we have to decide what our next steps were from that point.

Okay. And then 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 same markup on that. I mean how much sharing would go on with the customers…

There's no -- there's no sharing on that. It's -- but we're also again that being specific about who might want to be a participant. Yes, yes again this isn't yes if we pursue the JV.

Okay, so I’m presuming it wouldn't be fair to presume that there's a fair number of the customers that would want to be.

I -- wouldn't yes I wouldn't I wouldn't lean into that John. I think that they are generally in different businesses than owning pipelines if you look at this rate of customers. So I'm just not precluding any potential option there.

Okay. That’s really helpful. That’s it from me, thanks so much.

Our last question from the queue is from [Indiscernible] from Seaport Global Securities. Your line is now open.

[Indiscernible]

Thank you. In terms of you can expect that it would be at five 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 re-contracting for those pipelines, I think in GPL especially had some contracts which were coming up for renewal, any color on that?

Yes I mean, I would say overall we've got good interest in good rates, we were contract tender really has gone and increased over the course of the year and then why would it think about in GPLs it really has, it touches all the major demand and supply areas that are engaged in the market right now, whether it be LNG, whether it be [indiscernible] petrochemical growth and those whether it be certainly Marcellus, Utica and even the Permian we are seeing some action out west as well so, good prospects along as you go.

Okay. Thanks guys.

Okay. Thank you all very much. Have a good evening. I know everybody is going to [scurry] home to watch the big debate tonight. But you should be reading your Kinder Morgan information instead. Thank you and have a good evening.

Thank you. And that concludes today’s conference. Thank you for participating. You may now disconnect.