Richard Kinder - Executive Chairman Steven Kean - President and CEO Kimberly Allen Dang - Vice President and CFO Tom Martin - President, Natural Gas Pipelines.

Jeremy Tonet - JPMorgan Chase Shneur Gershuni - UBS Brandon Blossman - Tudor, Pickering, Holt & Co.

Brian Gamble - Simmons Darren Horowitz - Raymond James Kristina Kazarian - Deutsche Bank Ted Durbin - Goldman Sachs Craig Shere - Tuohy Brothers John Edwards - Credit Suisse Becca Followill - US Capital Advisors Matthew Russell - Goldman Sachs Danilo Juvane - BMO Capital Markets Corey Goldman - Jefferies & Company Ross Payne - Wells Fargo.

Welcome to the quarterly earnings conference call. [Operator Instructions] This call is being recorded. If you have any objections, you may disconnect at this point. Now, I’ll turn the meeting over Mr. Rich Kinder, Executive Chairman of Kinder Morgan. Sir, you may begin..

Okay, thank you, Shaun, and welcome to the KMI first quarter investor call.

Before we begin, I would like to remind you that today’s earnings release and this call include forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 and the Securities and Exchange Act of 1934 as well as certain non-GAAP financial measures.

We encourage you to read our full disclosure on forward-looking statements and use of non-GAAP financial measures set forth at the end of our earnings release, as well as review our latest filings with the SEC for a list of risk factors that may cause actual results to differ materially from those in such forward-looking statements.

I’ll start the call and before I turn it over to our CEO, Steve Kean, and our CFO, Kim Dang, I’d like to give you a quick overview of our strategy at KMI. The first point I would make is that this quarter’s results again demonstrate that we remain a strong generator of cash even in these chaotic times for the energy sector.

Second, as we’ve said previously and at our meeting in January, we do not anticipate any requirement to access the equity markets for the foreseeable future. We also do not see any requirement to access the debt markets for the foreseeable future, except for rollovers in years subsequent to 2016.

We’ve again reduced our expansion CapEx, Steve will take you through that, for 2016 and we expect that trend to continue in subsequent years through both high-grading our projects and entering into selective joint ventures.

We expect to fund the necessary CapEx out of our cash flow and continue to improve our debt to EBITDA ratio, thereby preserving and strengthening our investment grade balance sheet.

As our cash flow achieves those objectives, funding our CapEx and strengthening our balance sheet, we will obviously have excess cash which we will then use to either raise our dividend, purchase our shares, or for new projects and/or acquisitions, but only if they are solidly accretive to our distributable cash flow per share.

And with that, I’ll turn it over Steve..

Okay, thanks Rich. I’m going to hit on three topics before giving you some segment highlights for the quarter. First, an update to our capital projects and our expected growth spend for 2016, an update on our outlook for the balance of 2016 and some thoughts on our counterparty credit risk.

With respect to the capital update, we announced today a reduction in our project backlog of $4.1 billion, so from $18.2 billion down to $14.1 billion. The two biggest adjustments are the removal of the Palmetto Pipeline project, which is a reduction of $550 million and the market portion of the NED project, which is a reduction of $3.1 billion.

With respect to NED, we worked very hard; this is our Northeast Direct project, serving – or that would have served New England market. We worked very hard to get customer commitments on the project. And while many of our LDC customers did sign up, we did not receive enough contractual commitments from electric customers to make the project viable.

So we will fulfill our obligation to consult with our customers over the next 30 days or so, but this project is not economic, so we’re removing it from the backlog. In both cases, NED and Palmetto, based on all the facts, we believe this is the right outcome for our investors.

To be specific, the return on the NED project at the level of commitments that we have would be less than 6% unlevered after tax. That’s clearly not viable and we are far better off having that cash available for other uses, whether that’s continued and even accelerated delevering, other investment opportunities or returning value to shareholders.

We value our New England customers and continue to believe along with many others that additional capacity is needed in the region, but we’ll have to look for other ways to serve some part of those needs. We didn’t get there on this one and the action we’re taking is undeniably the right call for our investors.

We previously wrote off, I’ll remind you, our NED Supply project and we never had that one in the backlog. On the Palmetto pipeline, essentially the Georgia legislature prevented us from getting eminent domain and also prevented us from getting other state permits.

We were making good progress with land acquisition even without eminent domain, but we needed other permits which Georgia has now put a moratorium on. We needed environmental permits, for example, which they’ve now put a moratorium on until mid 2017. So as a result, we are not moving forward with Palmetto.

We had some other small adjustments to the backlog, including putting about $160 million worth of projects in service during the quarter. We had some cost changes which netted to a reduction of $254 million in the overall backlog and we had some other scope additions and removals which essentially offset each other.

So looking at the bigger picture on our capital project spend, we continue to high-grade our capital investments to ensure that we’re securing our investment grade credit metrics and maximizing the returns we get for the capital that we do deploy.

We’re aiming to reduce spend, improve returns, and selectively joint venture projects where that makes sense. We’ve reduced our expected 2016 spend by an additional $400 million to $2.9 billion.

So that compares to the $3.3 billion that we projected in January for 2016, which in turn was $900 million down from the $4.2 billion that we projected in our preliminary 2016 guidance, which we sent out last December. So we’ve continued to work through our backlog and high-grade where we’re spending our capital.

With respect to joint ventures, as we discussed at the January conference, we’d be pursuing these where they made sense that is where we could share the capital spending obligation on a particular project with a third party, get paid a reasonable value for having originated the opportunity, et cetera.

Those processes are competitive and confidential, so only going to be able to give you limited details. But the summary is that the process is going well and we currently expect to achieve the results that we built into our plan. We’re also taking care to not be dependent on any one transaction.

These processes can be unpredictable and we will be in a position to back away from a given transaction if acceptable value does not materialize.

Overall, as we complete projects and further high grade the backlog, as Rich mentioned, we will free up cash that we can use to reduce debt, return cash to investors in the form of buybacks and dividends or invest in attractive projects or acquisitions or some combination of those.

Now for the 2016 outlook update, we have looked at the potential impacts for the remainder of 2016 due to continued weakness in the sector. We now estimate on a full year basis for 2016 a negative impact of about 3% to the EBITDA that we showed in January.

But because of our ongoing efforts to high grade our capital spend and to pursue the joint ventures where it makes sense, we expect to meet our investment grade credit metrics, notwithstanding the 3% reduction. That 3% EBITDA reduction translates into a 4% reduction in DCF.

As the year goes on, we will try to mitigate that negative, but we are not assuming in this outlook any dramatic turnaround for our producer customers by the end of the year as some analysts have predicted.

Now, we’re not happy about any negative to plan, but I think when you put this in the context of the dramatic production declines particularly in the Eagle Ford, which is down 28% on oil from its peak and 15% on gas and credit weaknesses, our business is really diversified and insulated from the full brunt of the weakness in the producing sector.

So here are the two main contributors. A little under half of the deterioration is attributable to lower Eagle Ford volumes and those flow through both our midstream group in the gas business unit and also in our products group. And again this is all comparing to our original outlook, so this is not a year over year look.

This is versus our January outlook that we presented at the conference. So a little over half attributable to the Eagle Ford; another 20% is attributable to the coal customer bankruptcies.

So there are a lot of other pieces and Kim will take you through some additional details, but those are the two big chunks contributing to the degradation in the forecast. So while the current year outlook for North American energy production is experiencing weakness, we’re still bullish on the longer term.

We believe that we’ll continue to see more of our North American energy needs met by North American energy production that will grow our exports; we’ve already been growing refined products, natural gas to Mexico. I think we’ll continue to see growth in natural gas and natural gas liquids exports.

And those long-term trends are good for North American energy midstream companies like Kinder Morgan. Okay, the third general topic is counterparty credit. We’ve been monitoring counterparty credit very closely, but beyond monitoring we’ve been taking action, have been calling on collateral, putting other credit support arrangements in place.

A few points about our particular circumstances. Given our diverse business mix, we’ve got a very broad and diverse customer base. We’ve got producer customers, of course, but we also have integrated energy companies, gas and electric utilities and industrial users of our services. We’re not exposed to any single sector, commodity or service.

That diversifies our exposure, which reduces our risk. Our top 25 customers constitute 44% of our revenue. And of that revenue, 85% is investment grade. Of our total revenue, about 75% is investment grade or has substantial credit support and 86% is rated B or better.

In our business, real exposure is more complicated than simply looking at our customers’ rating.

In many cases, the rights our customers hold are valuable to third parties or essential to the revenue generating activities of those customers and therefore will be needed on an ongoing basis by the customer or in the worst case the debtor in possession in bankruptcy or a subsequent purchaser.

We analyze all of those factors and mitigation to get to our credit concern list. Our identified credit concern list amounts to about 5% of revenue and about half of that is mitigated by credit support or underlying resale value of the capacity that the customers hold.

And those numbers, that 5% and that half of five percent include Peabody, the Peabody bankruptcy which we’re now reflecting, so the going forward number is less than that. We’re reflecting Peabody, the Peabody bankruptcy in our forecast update. So in the segments, few highlights looking at the first quarter 2016 to Q1 of 2015.

The overall summary is this. On an earnings before DD&A and certain items basis, three of our five business units grew year over year.

Gas was up 4%; products pipelines was up 17%; terminals was up 2%; Kinder Morgan Canada would have been up year over year but for the effect of a weakening Canadian dollar; and CO2 was down 21% as a result of lower commodity prices and some lower production.

On natural gas pipelines, we had very strong performance on TGP and the contributions from our Highland midstream acquisition. So we split the Highland acquisition between our midstream business unit in gas and our products pipelines for the Double H pipeline.

So contributions from really, really strong performance on TGP and the contribution from our Highland midstream acquisition that we made in the first quarter of last year and those two things more than offset weakness in our other midstream assets and in our western pipelines.

The midstream weakness is largely gathering and processing in the Eagle Ford, and on a year over year basis, gathering in the Haynesville. In the west, year over year growth on our [ET&G] system was more than offset by weakness in Cheyenne Plains, WIC, CIG and TransColorado as the fundamentals for bases pipes out of the Rockies continues to degrade.

Natural gas needs for transportation and storage services, we believe, should grow over the medium and long term as power generation exports including L&G and exports to Mexico and pet chem and industrial demand continue to grow.

Over the last two years, the gas group has entered into new and pending firm transport capacity commitments totaling 8.2 bcf and I think importantly about 1.8 bcf of that was existing previously unsold capacity. And we currently estimate that we move about 38% of the natural gas consumed in the United States on our pipeline.

Moving to the products segment, the 17% year over year growth in segment earnings was driven by growth in KMCC, that’s our Crude and Condensate pipeline of Eagle Ford and the full quarter operation of the splitter, the first splitter in the Houston Ship Channel. We have both splitters up and running in the Houston Ship Channel.

We also saw good refined products transportation growth, 2.3% increase year over year.

And while Eagle Ford volumes have declined overall and we are projecting some decline on our assets as we look forward, we have seen volumes grow on our KMCC pipeline as projects have come on and we think that’s due to the pipe is in a great position, it’s serving a great part of that market, it has good upstream and downstream connectivity and good contracts.

Now, we think we’ve just started to see some flattening in that pipeline. But if you think about what’s happened in the Eagle Ford overall, what we’ve done on this pipe is essentially dramatically grow our market share out of the basin on that pipe. CO2, we saw earnings before DD&A decline 20% year over year to $223 million for the quarter.

Production net to our interests was down 7%. And I will point out SACROC was down, but [just you can] confirm this, but I think we had our highest quarter probably in the fourth quarter of 2014 at SACROC and then our next highest was in the first quarter of 2015. So a very strong quarter in 2015 that we’re comparing to our 2016 performance.

The CO2 group has – while I also mentioned price, the weighted average realized price has declined about 18% year over year and of course that’s a big part of the explanation for the downturn on a year over year basis.

CO2, on the bright side, CO2 group has been very diligent in reducing costs and husbanding our capital to the very highest available return opportunities.

And I will say perhaps somewhat counterintuitively third party demand for CO2 under our arrangements with them has stayed strong or roughly flat year over year on CO2, notwithstanding the deterioration in commodity prices. Moving to terminals, terminals was up 2% year over year.

Growth in this business came from expansions and acquisitions which slightly more than offset the weakness in our bulk business and that’s been driven primarily by bankruptcies of our coal customers.

Most of our liquids terminal business is in refined products and we’ve continued to see high utilization and generally good pricing on rollovers and renewals there and we continue to have a very strong outlook for the great liquids terminals positions that we’ve built in the Houston Ship Channel and Edmonton.

Kinder Morgan Canada, the Trans Mountain expansion project, so again, this is under long term contracts with customers.

The three key areas of focus for us remain getting the NEB recommended order and the cabinet-level Order in Council from the federal process, consultation and accommodation with first nations and thirdly satisfaction of the BC government’s five conditions. We’re making progress on all three.

With respect to the NEB, we got our draft conditions last August. We believe that they are manageable, but we did seek some important changes, particularly around the time required to approve certain portions of the build.

We now have the outline of the further process to be conducted by the federal government during the Order in Council process, which is expected to result in a final order. They have scheduled the final order for December 20 of this year.

We’re making good progress in meeting the consultation and accommodation obligations we have with the first nations and we’ve added mutual benefit agreements that bring us to a number, a majority of the bands that are most directly affected by the project actually supporting the project. On the five conditions, we’re still working on those.

We are engaged actively with the BC government on those. The BC government is also going to be conducting an environmental review under their provincial process. We expect that both of those things will be concluded within the same time frame of the federal process, maybe not the same day, but within the same general time frame.

And we have this project in the backlog and we are aiming for a 2019 completion, end of 2019 completion. And that’s it for the segment updates. With that, I’ll turn it over to Kim..

Okay, thanks, Steve. Today, we’re declaring a dividend of $0.125 per share. That’s consistent with our budget and the guidance we gave you in December of last year.

But most importantly, we generated $954 million of DCF in excess of our dividend, which as Steve and Rich pointed out insulates us from the challenging capital markets and significantly enhances our credit profile. Let me explain what I mean when we say significantly enhances our credit profile.

If you compare our coverage ratio and that’s DCF divided by the dividend, in the first quarter of last year which was 1.2 times versus the 4.4 times in the first quarter of this year, we have significantly more retained cash flow, approximately $750 million and therefore we have no capital markets risk to getting equity raised.

In addition, our previous funding policy was to fund our expansion CapEx 50% equity and 50% debt. Now, we’re using 100% retained cash flow and therefore our balance metrics will improve more quickly than under our prior funding model. Before we get to DCF, let me point out a couple of things on a GAAP income statement.

You will see that revenues, net income available to common shareholders and earnings per share are down. As I say many quarters, we do not believe that these measures or changes in these measures are necessarily a good predictor of our performance.

We have some businesses where revenues and expenses fluctuate with commodity prices, but margin generally does not. In addition, these numbers can be impacted by non-cash nonrecurring accounting issues or what we call certain items. For example, if you look at revenues, revenues are down $402 million or 11%.

However, if you strip out the certain items, with the primary certain item impacting revenues being the CO2 and the mark to market on our other hedges, revenues would be down $316 million. When you compare that $316 million to the $359 million reduction in cost of goods sold, gross margin is actually up.

Again, that’s largely because we have some businesses where both revenues and expenses fluctuate with commodity prices.

With respect to net income, if you strip out the certain items, and I’ll go through those with you in a minute, net income before certain items was $446 million compared to $445 million for the same period in 2015 or essentially flat.

EPS before certain items, and here when you do EPS, earnings is defined as net income to common shareholders, so after the payment of the preferred, EPS before certain items was $0.18 versus the $0.12 that you see on the page for the first quarter of 2016 compared to $0.20 in the first quarter of 2015.

So while stripping out certain items from earnings does help, we still believe that the best indicator of our performance is the cash we generate, which we measure as distributable cash flow and distributable cash flow per share. So let’s turn to the second page of the financials which I believe will give you a clear picture of our performance.

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

The segments were up by $28 million as Steve mentioned or 1%, with the increases in natural gas and products which combined for an increase of $85 million, slightly offsetting the $58 million reduction in CO2, which was driven largely by lower crude price.

The $28 million increase in the segment was offset by a $39 million increase in our preferred stock dividends. If you remember, we issued preferred stock in the fourth quarter of last year.

Now, there are other moving parts, but if you take the $28 million from the segments offset by the $39 million, that gives you a decrease of $11 million versus a decrease in DCF that I mentioned of $9 million. So that gets you almost all of the change. DCF per share in the quarter was $0.55 versus $0.58 for the first quarter of last year.

DCF per share was down slightly due to the additional shares we issued during 2015 to finance our growth projects and maintain our balance sheet.

Therefore, despite an almost 30% decline in commodity prices versus the first quarter of last year, our performance was relatively flat and we believe that this demonstrates the resiliency of our cash flows generated by a large diversified platform of primarily fee based assets.

There are a couple of certain items in the quarter that I want to highlight for you. Certain items in the quarter totaled $235 million loss on a pretax basis, about $132 million loss on an after tax basis.

$170 million of the pretax loss was driven by the write off of costs associated with the NED market and the Palmetto project, which as Steve mentioned have also been removed from the backlog.

$85 million was associated with losses on asset disposals and impairments in four of our business segments, with the most significant items being in CO2 and terminals.

And CO2 is primarily associated with the write off of the CO2 recapture plant due to lack of expected volumes and in terminals it was due to lost business at three of our bulk terminals. There was a certain tax benefit of $103 million and that’s primarily just the tax impact of the certain items at approximately 35%.

As Steve mentioned in the comments, we currently expect EBITDA for the year to be approximately 3% below our budget and DCF to be approximately 4% below. Now, for the first quarter, we did better than that with EBITDA about 2% below our budget and DCF about 1% below our budget.

We believe our outlook is consistent with the current environment and producer decisions and we’re not assuming any improvement. Let me give you a little more granularity on expected segment performance for the full year versus our budget.

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

CO2 is expected to end the year on its budget. We expect prices to be essentially in line with our $38 per barrel in our budget and cost savings to offset any weakness in oil production or CO2 volumes. We expect terminals to end the year approximately 4% below its budget, primarily due to the impact of the Peabody bankruptcy.

We currently expect products to be about 6% below its budget, primarily due to lower crude and condensate volumes on KMCC, Double H and Double Eagle. Right now, we are projecting KMC to be slightly below its budget for the full year due to higher book taxes, but remember the book taxes while they impact the segment have no impact on EBITDA or DCF.

With respect to interest, cash taxes, G&A and sustaining CapEx, on a combined basis, those items are expected to come in slightly positive to budget or said another way generate a favorable variance, with the positives interest and sustaining CapEx more than offsetting the negatives on G&A and cash taxes.

The negative variance on G&A is driven by lower capitalized overhead as a result of the lower expansion capital that Steve mentioned and interest expense is expected to be lower than budget due to lower LIBOR rates. And with that, I’ll move to the balance sheet.

We ended the quarter with $41.555 billion and EBITDA for the trailing 12 months was about $7.4 billion, which results in a debt to EBITDA of about 5.6 times, consistent with where we ended the year last year. And as Steve mentioned, we still expect to end 2016 at 5.5 times, consistent with our budget.

Our debt was up in the quarter, an increase in debt of about $330 million since the end of the last year. So let me reconcile that for you. We generated DCF in the quarter, as I mentioned a minute ago, of $1.233 billion.

We spent about $700 million in CapEx, we spent about $245 million roughly on acquisitions, with almost all of that being associated with the BP acquisition and we contributed about $44 million to equity investments, about $990 million roughly attributable to our expansion CapEx program.

We paid dividends of $279 million and then there were working capital and other items that were a use of roughly $300 million. When you look at the use of working capital, about – over $150 million of that was associated with accrued interest.

And when I give you the DCF figure of $1.233 billion that has three months of accrued interest in it, but we make interest payments twice a year. We make them primarily in the first quarter and the third quarter and so we make cash interest payments in the first quarter attributable to six months.

So you have a working capital use associated with that incremental six months of cash going out the door, which is different from the three months of accrual that’s in DCF. The other working capital use in the quarter was primarily associated with property tax and there’s probably about $100 million associated with that.

Again, we have about three months of property tax accrual in the quarter. By the time you get to the end of the year, you have 12 months of accrual, but a lot of our property tax payments are made for the full year in January. And therefore, relative to DCF, you have a working capital use in the quarter.

In future quarters, you will have a working capital source. And that gets you to about $330 million increase in debt. And so with that, I’ll turn it back to Rich..

Okay. And at this time, Shaun, we will take questions that people may have..

[Operator Instructions] Our first question comes from Jeremy Tonet, JPMorgan..

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

I’ll start with the two big pieces and then Kim has some additional detail. But as I said, about just – a little under half of it, a little under 50% of the reduction is attributable to lower Eagle Ford volumes than what we had in the plan.

So I talked about volumes being up year over year, but versus what we had in the plan, we had lower Eagle Ford volumes. And that impact – that’s trying to sum up everything. So that is on our Eagle Ford gathering system itself, on our [TK header line] and the processing facility.

It’s also volumes that we’re entering into our Texas Intrastate system that we expected to be able to move on that system and collect transport fees. So it’s kind of from end to end almost on the Eagle Ford volumes through our Texas assets.

The other place where we have exposure of the Eagle Ford volumes is in our products pipelines where we have the KMCC pipeline and the splitter. And we’d expected the splitter in our plan to run a little bit above its contract minimums. We have good contracts with good protection there.

It’s running – we’re expecting to kind of just run at the minimums, which are pretty good. I mean, it’s a pretty high percentage of the capacity of the facility, but we had budgeted a little bit more there. And KMCC, we expect we’re now going to start to see some volumetric decline on that. Again, that’s all versus plan.

So that’s a little – if you just say – and look, there are lots of different ways to rack up these numbers, but that’s – those factors, the Eagle Ford volumes as they impact two of our business units amount to about half, a little less than half of the adjustment. Another 20% is attributable to the coal company bankruptcy.

So those are the two very big pieces..

And then as far as the decision to take NED off now versus later, can you just walk through the timing to it? And then also just if you’re looking to high grade the growth CapEx backlog, are there any other items that are kind of coming under closer scrutiny that you could point us towards or you kind of feel like where the backlog is right now is a good place for where you want it to be?.

So on the first point and I want to separate that a little bit from the high grading discussion because, look, we gave it our all on NED. I mean, we pursued customers hard, we pursued approvals hard. In the end, the customer commitments just weren’t there.

Now, that makes the project uneconomic not surprisingly and that’s why I wanted to specify the return for you. It’s apparent, it’s objectively apparent that the project is not economically a viable project at that customer sign up level.

And so we said at the conference we’re going to make a big push in the first quarter to try to get customer commitments in and sell down some of the equity to customers, not a lot of takers at that return as you might expect and so we put on a hard push to try to get done and it’s just not forthcoming.

We have one significant prospective customer who determined to put their volume someplace else and that was a significant negative for the project.

So that’s how we got to that decision in the time that we’re talking about now, but I want to go back and underscore again from an investor standpoint, in light of that return, we are a lot better off with that $3.1 billion back in our pockets and being put to some other use.

The project wasn’t going to produce the return that would be required to make it viable, because again the contracts weren’t there. We’re better off having that money back.

I think if you look through the rest of the backlog, my guess is we’ll find some bits and pieces here and there that will either will save some money on or may change the timing a little bit.

I still think those are high probability projects though and ones that we want to build out and do and they contribute to our DCF per share growth that we’re aiming to achieve by building it out..

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

But on the non-CO2 projects, the average year one multiple, EBITDA multiple is 6.7 times..

And then one last one if I could, just curious how you guys think about high level now as far as – with the backlog standing at $14 billion, the size of the entity as it is right now, what type of EBITDA growth do you guys see yourself being able to achieve? Is there anything different than what you guys have communicated historically as far as base growth that this business can throw off?.

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

You take out the CO2 from the $14.1 billion and then you’ll get roughly – it’s going to be in the range of $1.8 billion and all but [$175 million] is incremental to 2016..

Next question on queue is coming from Shneur Gershuni of UBS..

First question just a follow up on the discussion on CapEx, when I look at it for 2016, you’ve now revised it lower again, which I guess is good in this environment. You also mentioned that in terms of pulling NED out about how you’re focusing on returns, I think you’d made a general comment about just trying to high grade returns and so forth.

The change this year, how much is related just to the removal of NED and Palmetto verses – have there been any improvements in costs, are you able to beat up your contractors a little bit further to improve returns? I was wondering if you can also talk about I guess on a delta basis what the impact would be of the removal of NED and Palmetto on the 2017 budget? I realize that obviously that has not been presented, but just what the delta of what you would have expected to spend on those two projects in 2017?.

I don’t have the 2017 CapEx numbers. I think Palmetto – and I’m speaking with respect to the backlog, so Palmetto was about $550 million and of course NED was about [$3.3 billion]. So that explains most of the backlog reduction. On the CapEx front, it’s a mix of things.

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

As we said at the beginning of the year we made some JV assumptions as well..

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

The cost reductions, is that something that we can see more on a go forward basis, because it was interesting you used the language of improving returns or if that’s just totally about high grading?.

optimizing scope, reducing cost and adding revenue..

And then I was wondering if you can just sort of turn to Trans Mountain a little bit, I mean obviously you took NED out because of returns issue.

At this stage right now, is Trans Mountain at risk for the same thing regardless of what happens on the approval process or are the returns that you expect, you know what, it’s your latest update, does it look – is it close to your return hurdles, well above your return hurdle and I was wondering if you can comment about some of the comments that the Canadian government made last week with respect specifically to pipelines, do you view that as a positive or do you just sort of continue your focus as this?.

Huge, huge difference between NED and Trans Mountain. Trans Mountain is under contract. That’s an enormous difference. We were fighting to get NED under contract and didn’t get there. Trans Mountain has the contracts in place, 20-year contracts for 93% of the volume and the other 7% is on a 15-year contract.

So long term contracts and look the overall picture, I mean, the overall picture in Canada is notwithstanding very, very difficult [net backs] up there, right. They are taking a very long view, producers are taking a long view and they’re finishing out projects that they’re well into and the oil sands become a very stable source of production.

It’s not like the shales where it ramps, you get a high ramp up in the beginning and it falls off rapidly, so there’s an actual projection of an increase in production in Canada. At the same time, the transport options out of Canada are becoming more limited. So our customers still want to do this project and we do too and the returns are good.

Switching to the public opinion or the governmental outlook, I would say just very broadly that the tone of the comments in the public arena up there are improving.

I think that there is a recognition that getting Canadian natural resources to points where they can be exported and no longer dependent upon solely the US market is a good thing across Canada.

And that’s starting to show up as people are being constructive about, okay, we need to approve projects, we want to approve them with – we want to have the right conditions and the right process around that approval, but there’s been a switch I think toward, momentum toward getting the project approved. Now, I’ll say that with an important caveat.

We don’t know what their conditions ultimately are going to be in the end and we’ll have to make an assessment of that when it’s all in. We certainly have a good handle on what the NED proposed conditions are going to look like, but we don’t know what if any other conditions may be imposed.

So we’re going to have to watch for that very carefully, but we’ve got good returns, good underlying customer support and contractual support and an improving tone, I think, in the in the public sector today..

And one last final question, if I may.

Earnings up year over year and if you sort of take out some of your negative charges related to coal bankruptcies up a little bit more, I was wondering if you can sort of break down how much the delta is due to acquisitions for example like Highland verses some of your growth projects coming online? Is that a good way for us to assess the returns relative to the CapEx that was spent last year?.

I don’t have a breakdown of what is attributable and aggregate to expansions and acquisitions. But I mean I think you can assume it’s probably more than that year over year change..

But I think you can also just include the capital from the acquisitions in your denominator you’re trying to get a return. We think about our acquisitions as investing capital and it’s important to get returns on that capital as on the expansion CapEx..

Absolutely.

I was just more trying to figure out if the returns were higher from organic versus your acquisitions and so forth?.

Generally that is the case..

Yes, generally yes. In the acquisition context, you look a little differently at something that’s already up and running, already producing cash flow versus a start from scratch investment and an expansion where you’re going to be putting money out before you see the cash in and you’ve got construction risk and other things to take into account.

So you generally aim for higher return..

Next question is coming from Brandon Blossman of Tudor, Pickering, Holt & Co..

I’ll start smaller line item, but interesting nevertheless, I think.

NGPL, there’s a little bit of balance sheet support there during the quarter, any incremental color available on how that balance sheet progresses over time on a look forward basis and EBITDA expectations as we move through the year into next year and maybe some incremental contracts of that pipe?.

Generally, I mean, we contributed $311.5 million. That contribution is the original $3.3 billion expansion CapEx budgeted, it is in the $2.9 billion revised. So all taken into account and our guidance generally versus 2015, NGPL’s EBITDA is increasing as a result of some of the expansion projects that it is bringing on line..

And Kim, any expectation of incremental support there or does it look good on a go forward basis?.

No expectation for further contributions in 2016. And in 2017 and beyond, we’ll just have to evaluate that as we get there..

And then I think Steve you mentioned some other alternatives to getting gas to the northeast other than the Northeast Direct, is there anything that we could look to or think about in terms of alternate strategies there or incremental projects that may be possible?.

I’ll give you a couple things, but then – and Tom if you have anything to add. I mean, I think we haven’t even – we’ve just barely started those discussions and so it’s just too early to give you anything that’s very specific.

I do think that one general observation is that the NED project had scale and so the tariff was better likely than what smaller project development tariffs would be. So it’s not likely to – it’s not going to be anything that’s going to add up in the end to an NED size project. It’ll be bits and pieces here and there. Tom, is that....

Yes, that’s a fair assessment. I mean, we’ll just have to work with particularly our LDC customers and see what we can do on an expansion of the existing [PTP] system and see if there’s something there that works.

But probably there is need both in the near term and ultimately we believe in the long term in the region, but we’ll just try to scale up with that demand as it develops..

And then as a follow up on that one, this is a big picture question, not Kinder specific, but just generally about Northeast infrastructure, any comments that you care to put out there in terms of projects that are needed, but contrasted against producer balance sheets and the ability to kind of backstop those projects, do you see any issues over the next two or three years in terms of getting gas out of the basin?.

I think it’s obviously harder for producers to commit and we’re seeing that in our business to commit to large expansions, to move gas out of the basin.

I think on the other side of the – the other end of the pipe, I mean, we think and a lot of other third parties have pointed out that the New England market needs natural gas and needs additional natural gas. And so we think that need is already there.

But there is a regulatory process that has to get sorted out up there for how the power part of the business is going to procure the needs for their generating assets. And that’s been a work in progress and who knows when they ultimately get that resolved. So there’s definitely less producer push activity for anything large.

And we think on the demand side infrastructure is still needed, but they’ve got to come to terms with how it can get contracted for..

The next question on queue is coming from Brian Gamble of Simmons & Company..

I wanted to start on the NED project and if you just finished up chatting about that, when you mentioned essentially the commitment level is not enough from the electric customers, was there any single reason Steve that you can point to is kind of the biggest reason for non-commitment and then any color you want to give on why that one specific customer that you mentioned went a different direction would obviously be helpful, just to get a little flavor for what’s going on up in that market?.

I’m not sure I want to get into that customer’s particular thinking and thought process and the choice they made. I think that the main thing from our standpoint is we needed that and we needed additional sign up. And the insight into why we didn’t get it, we don’t think it had anything to do with the quality the project, it’s a good quality project.

We think it relates to the thing I closed the last answer with which is that the processes up there just have not fully formed in a way that will allow the electric generation load that needs firm natural gas infrastructure on a long term basis to get approved and costs passed through.

And so I think those are the two things that really kept us from getting where we needed to go on the electric part of the business, not because that was in theory already in our proposal..

And then on the impact to the 2016 outlook, you walked through the Eagle Ford volumes and where they’re hitting your system.

Stepping back from that, why do you think those volumes are lower? Do you think from your previous expectation it’s lower activity level in the basin or do you think you’re getting lower contribution from existing wells, so the decline curves are higher or is it a combination?.

It’s really lower activity. I mean I think the rig count there is 40% below what we were looking at and thinking about in October. And so it doesn’t mean it can’t come back at some point, there’s oil window, there’s an NGL window and all this is associated production, the gas that’s coming out is associated gas.

But I think that takes commodity price recovery for people to come back and start deploying rigs and completing wells and the rest of it..

It’s a nationwide phenomenon. I think we gave figures at the start which you might get again, the decline built in oil....

Oil was down 28% from its peak, gas 15% and so there are big declines.

I mean, again I think KMCC’s resilience has been surprising and it’s really driven by the fact and you see this in the Bakken too that there are some places which are really core that there’s still some activity going on and that’s kept KMCC at relatively lofty volume levels comparatively, but the overall basin is in decline and will be until there’s price recovery that draws the rigs back out..

And what type of rig changes are you expecting from where we are today that’s baked into the new guidance?.

We just assumed that things did not improve and built in kind of an observed decline rate going forward and so we didn’t – so our numbers don’t translate into rig counts or numbers just like a continued decline rate, an extrapolation from current decline rate..

So I’d assume that Eagle Ford production from current levels continues to degrade throughout the year?.

Yes..

And then you touched on some of the progress from a JV standpoint, you gave a little color there, really just wanted to kind of touch on big picture, nothing specific, but the general attitude of third parties since the beginning of the year, any color you can give us on any changes that you’ve seen, any improvements, people that are more pessimistic than they were, what direction are they trending?.

I think all we can say is that the response to our JVs has been positive. And as Steve said, we anticipate getting completed what we talked about earlier in the year and what we have in our book..

The next question on queue is coming from the line of Darren Horowitz of Raymond James..

Two quick questions for me.

Kim, the first one on gas pipes, regarding that contract renewal deterioration that you discussed a few quarters ago, if you back out the Eagle Ford and the SNG expansion project issues, how much of that 2% segment profit shift is coming from areas where re-contracting is an issue like in the Rockies on either WIC or CIG?.

So you’re asking about the 2% versus our plan down for the year?.

Right..

There is maybe less than 10% that’s coming out of the Rockies pipes and it’s primarily associated with CIG..

And outside of any of the intrastate systems, just across the aggregate asset landscape, is there any other material re-contracting work or otherwise that we should be watching over the next 12 months?.

I think I’ll probably refer – in our conference presentation, I think we had a sensitivity over the years that this would be – I think this was actually in the appendix, right..

Darren, we have those numbers in, here it is, yes, so 2017 total TPG and this is stated in terms of our share of re-contracting exposure, 0.7% 2017 and 1.3% 2018. And I think, look, that’s probably attributed a fair amount to the Rockies assets..

And then last question either for you Steve or Rich, with regard to this common theme of being focused on return for equity holders here and obviously recognizing the ability to fund 100% of the growth projects with retained cash for the next few years that being at the top of the priority list, what is the quantitative target on leverage that you’re looking to achieve before you consider enhancing that equity value and also your preference between share buybacks, dividend increases or maybe a balance between both?.

Well, let me answer the first question first and that is we remain consistent with what we said previously that as we promised the rating agencies we will be in the range of 5.5 going down to 5 times debt to EBITDA and we would anticipate achieving the bottom end of that range on a going forward basis.

With regard to the second thing that will be a decision that we will make as that cash flow comes to fruition. And at that time, we would just look at all the factors and see what makes sense. I think it’s an enviable position to be and I feel that way as a large shareholder. And we’ll look at it.

If it makes the most sense to buy back shares at that time, we will buy them back. I can tell you if the prices are where it is today, $19, we would buy it back. But we’ll see where the price is and see what the market looks like and whether we benefit our shareholders in a better way by buying back their shares or by raising the dividend.

But we’ll have the capacity to do either one if we want to do that once we get more funding of our capital projects done and once we get our balance sheet in shape we want to get it in..

The next question on queue will come from the line of Kristina Kazarian of Deutsche Bank..

Thanks for the update on the backlog numbers. From my mind, it makes sense on those removals.

But when I’m taking that lower backlog now and thinking about looking in a little longer term towards 2017 and especially with your comments you just made Rich in terms of getting to that 5 times number, do I now have line of sight on getting to that maybe in 2017 time frame or am I thinking a little too ahead of myself there?.

We’ll just see how everything comes together and we want to get these joint ventures closed, we want to look at all of the high grade, we want to see exactly what comes out over the remainder of the year. But certainly, we’re getting closer to getting to that happy sun meadow where we can afford to make those choices..

And then when I am in that happy sun meadow at the end of 2017 on my numbers that means in 2018 I could have those conversations which you mentioned in the beginning of the call more strategically around growth than buybacks or deciding out on longer term additional incremental projects and stuff like that, right?.

I think that’s right..

And then my next question is we’ve had a bunch of conversations with peer – or you had a bunch of peers out there as well talking about contract written negotiations [in lines of] maybe given up on fees in return for longer term contracts or acreage dedication, can you just touch on what you guys are seeing on your side?.

Interestingly, we’re kind of in a net positive right now on the contract renegotiation front. We went through a process in our Highland midstream assets of – I think the easiest way to think about it is we had a deal to enable us to hook up more production out there and that was advantageous to the producers as well as to us.

We fixed our fees and took commodity exposure off and the producer wanted that, wanted to have the commodity upside. But the bottom line for us is we improved our position on a 2016 basis and improved our fee recoveries on those renegotiated contracts. So we’re up so far this year.

Now, other customers do approach us in the gas group occasionally on contract restructurings. So far we haven’t had to do anything that we didn’t want to do, meaning finding something that had mutual benefit, finding incremental revenues that we could – I’m sorry, incremental volumes that we could put on.

At the same time, we made some concession that they wanted. So I think they’ve been generally win-win situations, Tom, and so I think a pretty good story so far for us..

And we’ve done some credit enhancements..

We’ve done credit enhancements as part of the trade too..

And can you maybe talk in terms of credit enhancements, I know you mentioned earlier about conversations with customers asking them to put some more collateral, just how those are going, have you had any resistance on that side or just any color on that?.

We’ve pulled a lot of collateral and we’ve also done some other alternative things. We have interactions with customers sometimes in a number of places where we can put netting arrangements in place, for example.

Some of our producers, the cash flows through us before we net their recovery out and so we have other ways of enhancing our credit position. And I think to me at least the instructive number is what I said. We net everything through comp all of our collateral up, look at our position and the underlying value of the capacity.

If the customer decided they didn’t want it and went into bankruptcy, we see our credit concern list amounting to about 5% of revenue and about half of that is mitigated. And as I said, that already included the Peabody and so that’s now out of our forecast. So the going forward number is very small..

Next question on queue is coming from Ted Durbin of Goldman Sachs..

Just on Elba, can you just walk us through the milestones that we should be looking for? And I think you said that you pushed out some of the timing on the CapEx for this project this year..

The big upcoming milestone is May when we expect to get our FERC certificate and a milestone that just recently passed that we, I think, mentioned in the investor conference is we – well, it’s announced publicly, so our contract with IHI, so they’ll be our engineering procurement and construction contractor.

That’s a good milestone for us to get behind us that takes care of a lot of the construction risk. So we’re looking for our FERC authorization upcoming in the next month and we have our EPC contract behind us..

And what do you need still left on the FERC certificate, you have the EA, I think, but what’s left exactly?.

So they circulate it for inter-agency comment and we had hoped that, in fact, Kim mentioned the delay in – the impact of the delay on our Elba Express and SNG expansions that are hurting the south pipeline group in 2016. What happened essentially is FERC put together all of the – on the same timeline, all of the certificate discussions.

So we ended up with that delay as those projects were dragged into the overall Elba conversation, I guess, you’d say. What they’re doing right now is they’re getting inter-agency commentary. We’ve spent a lot of time with those agencies.

We think we’ve addressed, we think that the concerns are largely addressed and that’s the part of the process that they’re in now. So we do expect to get a 7C certificate in May..

And then if I can just ask, again just coming back to the JVs, there’s something you’re still pushing forward there even though you’ve dropped the backlog a lot, I guess, at some point we are going to run into a lack of growth potentially given delays in Trans Mountain and what not, how are you thinking philosophically about, do you back off of that if anything else falls out of the backlog, wanting to JV these projects.

And then if you can give us a sense of the returns that your JV partners would look for on an unlevered basis?.

I’m not sure I can give you one of the latter other than to emphasize what Rich said, which is there’s a lot of interest out there, so there is a fair amount of competition for people wanting to invest in these. We’re maintaining flexibility.

We think that the JVs that we’re pursuing do make sense and making sense in two ways, one is getting someone else to share the capital burden on the development end of it, but also we do believe that we will see a nice promote, nice compensation if you will for having originated the project and that helps boost our return on the capital that we do deploy.

So in other words, Ted, I think we think that these make, the ones that we’re pursuing make sense and we expect to continue to pursue them..

The next question on queue will come from the line of Craig Shere of Tuohy Brothers Investment Research..

Not to beat a dead horse with regards to the JV funding, but Steve, I think in your earlier answer to Jeremy, you kind of noted that NED was obviously expected to have some JV partner CapEx support.

With NED gone, can you quantify how much in terms of as yet uncommitted but budgeted JV dollars are left in the budget?.

We haven’t really included, we did attempt to get JV partners on NED, but we never really included that in our outlook. As I said at the conference we had kind of two placeholder numbers, two placeholder JV opportunities and it won’t be – it won’t match perfectly what we had in the original outlook in terms of which ones we pursue.

But we expect to meet our targets for what the JVs will do for us this year in terms of our capital, a reduced capital spend..

And in terms of juicing the returns on CapEx you do spend because of your value you get from originating the projects with JV partners, do you see this simply taking projects already earning 15% plus and juicing it all the more or do you see it taking projects that initially may not have been up to those standards, but can be pushed to those standards with the JVs?.

I mean, I think we first start by looking at what we need to do for our balance sheet metrics, but we do keep an eye on what the longer term impact of the JV decision is.

And we are picking projects that I think are attractive returns and that other people will find to be attractive returns, but we think that we can make better use of the capital that comes in from their participation in the JV, meaning them buying into the project and funding the CapEx.

We can redeploy that in any of the ways that Rich mentioned better. So I think it’s kind of both things that you are saying..

Next question on queue is coming from John Edwards of Credit Suisse..

Just a couple quick ones for me, I’m just curious how much – what was – maybe I missed it, what the write up amount was for NED and Palmetto?.

It’s about $100 million on NED and it was $65 million – $64 million on Palmetto..

Pretax..

And so you’re looking at that in terms of – how does that flow through on your budget, is it you’re looking it as kind of a non-cash item or is it hitting the EBITDA budget, is that part of the 3%, how should I think about that?.

We’ve set that aside as a certain item. And so you can see that on the certain items on the project write off, there’s $170 million and I just gave you $165 million of it..

And then I’m just curious you know, you brought the CapEx number down to $2.9 billion, is the bias here to reduce the CapEx budget more or I mean do you think you’re going to go forward here around this level?.

I think we believe this is a reasonable estimate here, but we will keep looking at it. And ideally what we’d like to do John is keep finding ways to save cost, improve scope, add customers to project to boost returns. So we’ll continue to look at it to improve it.

We are authorizing small additional projects, they’re very small, they have very good returns that build up on our existing network, but this number reflects all of that along with the reductions that we’ve been talking about on the call. So I think this is a reasonable estimate.

There’s the possibility of taking a little bit more out of it, but this is a reasonable estimate to use..

As far as taking a little bit more out of it, I mean do you think that’s going to come more from project deferrals or more cost reductions, how are you thinking there?.

I think it will be more within the project. In other words, we look at the project and it gets delayed or deferred or we find a cost saving in it..

And then with crude oil prices improving here obviously off mid quarter, we’re up about 50% or so, I mean what’s your read on customer mood now? I mean, is it cautiously optimistic, people still resisting project proposals or what’s the read through you guys you’re getting?.

I think that they’re being cautious about their next move. I think they want to see generally they wanted to see some additional recovery and see some stability in that recovery. I also think that as a group they’ve made themselves very, very flexible. I mean they are updating their outlook and updating their decision making.

It’s no longer an annual process. It seems like it’s a biweekly process or something now as they’re looking at things which suggests that when they do decide to turn things back up, they’ll be able to turn it back up relatively quickly.

But look, as I said before, people signing up for a long term multi hundred million dollar or a billion dollar infrastructure on the producer side, I don’t think that that’s in the cards in the near term..

Next question on queue will come from the line of Becca Followill of US Capital Advisors..

Believe it or not, there’s still questions.

Broad Run was delayed a year, can you guys talk about that a little bit, why the delay on that project?.

That was the Broad Run expansion project, so we have the first tranche of Broad Run in and that’s up and running. We talked to our primary customer there, Antero, about whether they still wanted to pursue the expansion project. They did, but they were interested in and we were interested in a delay in it. So we mutually agreed to a delay..

And then along the same veins of the answer to the last question, in your CO2 business, at what point do you start to put capital back to work and what kind of commodity prices do you need to see?.

We have capital going to work there right now. We have just elevated the return criteria to, as Kim said, 15% unlevered after tax or better. We actually approved a project today that had a 43% return. These are small. The capital program on CO2 is now just a little over $200 million, but we continue to approve small program spends in the CO2 group.

And I think that the easiest way to think about it, Becca, is where we’ve got an existing flood that’s up and running and so what we’re doing is using shared facilities, maybe adding an injector, converting a current producing well to an injector, drilling a new producing well, we’ve got all the other facilities, all the central facilities in place.

The return on the incremental capital spend that we make is still attractive. Now, if you’re talking about a brand new CO2 flood and getting one of those started, that’s ways off. I think you need to see a fair amount of oil price recovery before you start to see 50, 55, you need to see significant oil price recovery before you start to see that..

And then last question on interest expense, certain item of $69 million in interest expense, can you help us out with what that was?.

On the interest expense is that the fair value accounting, okay, so Becca, when we – and that should be a recurring certain item that happens every quarter. When we acquire other companies and assume their debt, we have to fair value that debt.

And once we fair value that debt, then the interest expense that we recognize is not the same as the interest expense that is on the note and the interest expense that we pay. And so we classified the difference as a certain item..

Next question on queue is coming from the line of Matthew Russell of Goldman Sachs..

I understand the stance on funding CapEx through cash flows, but just given the recent strength that we’ve had in the credit markets, any reason you don’t consider tapping the debt markets that have had $3 billion you have maturing in 2017?.

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

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

And then just thinking about the leveraging strategy more broadly, sitting at 5.5 times at the end of this year with $42 million in debt, the simple math is you could take out $4.5 million of debt and that would get you to 5 times or you could grow $900 million of EBITDA.

How do you see that mix between debt pay down and EBITDA growth playing out to get you to that 5 times?.

I think it’ll be a combination of the fact that we’re finding everything with 100% retaining cash flows, so 100% equity and then EBITDA that comes on line from the projects..

Next question on queue is coming from the line of Danilo Juvane of BMO Capital..

With respect to the 6.7 times multiple, are there opportunities for you guys to continue to realize cost reductions and scope improvements to get that even lower?.

I don’t think they’re dramatic, right, but we continue – we look at our projects every month within the business unit, certain of them are looked at every week and we’re pressing our vendors fairly hard to get concessions on construction costs, equipment and materials.

We have found scope that it turns out on closer examination we don’t need or we don’t need right away and so we can either defer or eliminate those. And it’s just part of our normal process too. I mean, we ramped it up a little bit here, but I mean it’s just part of the normal review process to look for those.

But they’re not huge, they may be material to an individual project, but not huge in the overall scheme of things. But I think we’ll keep finding them..

Last question for me, what was the CO2 CapEx for the quarter?.

CO2 CapEx for the quarter, hang on, it looks like about $55 million..

Next question on queue is coming from the line of Chris Sighinolfi, we have Corey Goldman of Jefferies..

Just a quick follow up to Shneur’s question on TMX. So it looks as though NED pushed its final approval back seven months.

Steve, can you just confirm it’s just a one quarter delay on the in-service there?.

We’re still aiming for end of – think of it as very end of 2019. So we had been looking at late third quarter and yeah it’s about a three month delay..

And so I think this was a question asked on the third quarter earnings call, but given that some of the shippers do have an opt out if cost begin to creep, is there a specified date that you guys have in mind in which you want to decide go, no-go before or do you think shippers will have a go, no-go decision if and when those costs begin to creep up?.

Let me lay out what the process is. So in the – we’ll be getting – again we have – we’re looking at costs right now, but we’ll have our final conditions and know what all of our obligations are going to be, we think December, January, right.

I mean, it’s December for the federal process to conclude and I think again out in that same time frame we will understand where we are with British Columbia. And then after that, we owe our customers an updated cost estimate. So you’re talking about – your question about timing that’s really kind of a first quarter of next year event.

We don’t have an update on the 6.8 because we’re still evaluating what we think the projects are going to cost us, what the project is going to cost us and it will be a bit dependent upon the conditions. I think a couple things. One is that there is some cost pressure, the Canadian dollar has weakened relative to the US dollar.

A lot of the goods and services are provided in US dollar terms, so there’s been some pressure there. There have been some conditions that we’ve agreed to and that have been added over time which has put some pressure on.

But I think at the end of the day what matters is do the customers want the project and we still have very strong interest from our shippers in the project and we even have interest from shippers who are not currently customers, potential customers who are not currently shippers on the project.

So we talk about this all the time, but I think this is still a project that our customers want..

And then Kim, if you can, can you just – I think you guys are alluding to some movement in the CO2 volumes as it relates to 2016 and perhaps beyond, can you just provide us an update on the hedges and then the price there from the analysts data if any?.

So in 2017, we have 51% hedged at $68 and 2018 it’s 36% at $72; 2019, it’s 24% at $60; and in 2020, it’s 6% at $49..

And 2016?.

This year, this is for the remainder of 2016, we’re 77% hedged at [$63.55]..

And then just if you can, last question for me, if you can remind me, of the $14.1 billion growth CapEx that you still have, how much of that considered overhead?.

5%..

Is that 5%?.

Yes, 5%..

So it’s not a huge amount, but would you recommend capitalizing that at 6.7 times multiple you’re referring to kind of including that in there?.

Yes..

We’re including that..

Yes, we’re including that one, we are using the full $14.1 billion which includes overhead, less the CO2 CapEx. And then that’s the 6.7 times multiple on that capital..

The next question on queue is coming from Ross Payne of Wells Fargo..

And Rich, thank you so much for your clarification on the leverage. And you guys are obviously going to get to 5.5 times by the end of the year, moving towards the 5.0.

Can you speak to what is the progression for 2017 and 2018, when do you need to be at 5.0, what do you expect in 2017 in terms of your leverage metrics as well?.

Ross, we haven’t done 2017 plan yet and so I don’t have a projection for you for exactly when we will get to the 5.0 time. But I think over the next couple of years, we will get to the target and that’s what Rich was referencing at that point that we will make a decision what to do with excess cash flow beyond that point..

Do the credit agencies have certain levels that they have in mind for 2017 and 2018, or they just thrown out of 2016 and then a general migration to the 5?.

Let me tell you I think the rating agencies based on our conversations with them are comfortable with our current rating and our current outlook. And I think at this point we are funding 100% equity because we’re using cash flow. And what we’ve said is we’re going to use that cash flow to fund our CapEx and to improve our balance sheet.

And until we get that balance sheet improved to the 5.0 target, we’re not going to do other things with that cash flow.

So we will absent our cash flow going away which as we said every year for the last 18 years that we have very stable fee based cash flow, we will have that cash flow, we will improve our leverage metrics and once that happens then we will look at other uses of our cash..

At this time, we have no question on queue..

Okay. Well, thank you all very much for listening in and have a good evening..

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