Kinder Morgan, Inc. (KMI) Q3 2015 Earnings Report, Transcript and Summary

Welcome to the quarterly earnings conference call. At this time, all participants are placed on listen-only until we start the question-and-answer session. [Operator Instructions] Today’s conference is being recorded. If you have any objections you may disconnect at this time. I would now like to turn the call over to Mr. Rich Kinder, Executive Chairman of Kinder Morgan. Thank you. You may begin.

Okay. Thank you, Vance. Before we begin I’d like to remind you that as usual today's earnings release and this call includes forward-looking statements within the meaning of 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. With that out of the way let me get to the meat of the matter. As usual, I’ll give an overview of the third quarter and in addition, try to put some perspective on the happenings in our portion of the energy industry. Then I'll turn it over to Steve Kean our CEO and Kim Dang our CFO who will talk in more detail about 2015 and the outlook for 2016. And then as usual, we'll take any and all questions that you may have. Let me start by reviewing our 2015 performance. We raised the dividend for the third quarter to $0.51 and we expect to achieve our target of declaring $2 for full-year 2015. As you may recall that’s an increase of 15% over 2014 and on top of that we estimate we will have excess coverage for the year of about $300 million. Now, that's less coverage than our budget which assumes $70 WTI and $3.80 natural gas prices, and Kim will take you through the details of that variance. But still substantial in our view at the level of $300 million. To me it demonstrates what we have been saying. That is that we are insulated from the direct and indirect impacts of very low commodity environment, but we are not immune. And I promise it to put things in perspective. And let me try that. If you take our $2 dividend and multiply it times with 2.2 billion shares outstanding. That's $4.4 billion of cash distributions to shareholders that we will make for 2015. If you add to that $300 million in excess coverage that means $4.7 million of free cash flow after payment of all our operating expenses, our maintenance CapEx, interest on our debt. Now we could have paid for all of our expansion CapEx for this year and had a lot of money left over. Our capital expenditure budget for this year is about $3.5 billion estimated for the full year. So with that in mind I think that this idea that midstream energy companies like Kinder Morgan are not sustainable generators of cash flow just doesn't hunt. Rather we elected to distribute the bulk of our free cash flow to our shareholders and then pay for our expansion CapEx with the combination of equity and debt and we intend to do this in the future. That said we intend to continue covering all of our dividends with our generated free cash flow and remain investment-grade, watch our CapEx closely and continue within those parameters to grow our dividend. We're going to be judicious about using common equity, and as Steve will explain we intend to use other means of raising equity so that we will not be required to issue common equity or access those markets through at least the middle of next year. Now let me also put in perspective our business and its prospects for the future. I talked about analogizing our business to a toll road that to the extent that you're probably tired of hearing it. I'm kind of sick of using it myself. And that phrase happens to be very true. But I want to give you some hard cold facts about the natural gas story which is our single most important business. As many of you know our natural gas operations produce over half of our cash flow and we move about a third of all the gas consumed in the United States. So, to put it very simplistically as natural gas demand grows, so do we. Now everybody talks about natural gas being the fossil fuel of the future because it's abundant cheap mastic and clean and that's all true. But I thought it would be interesting to give you some actual factual detail on what's really happening on both the demand and supply side of the natural gas story because it's so important to us and to other midstream companies. If you compare 2014 to 2015 with McKenzie is now estimated there will be an increase in demand year-to-year of 5%. Its projected increase from today's level of 76 Bcf a day to about 110 Bcf a day by 2025, that's an increase of 40%. Now, there are really four drivers of this growth. The first and probably the most interesting is electric generation. If you look at the 15 mix of generating output and this is according to the EIA, 32% is gas and 33% coal. For those of you who have been in this industry a long time or followed it you know that that represents a dramatic shift to the positive for natural gas. If you flash ahead again these are EIA numbers to 2030 their projection of the mix of generation is 39% gas, 18% coal. If you want to look at something closer to home or ERCOT in state of Texas through July of 2015 had a mix of 49% natural gas versus 39% a year ago. If you want to look at Kinder Morgan specifically our gas transportation volumes for electric generation are up 18% year-to-date 2015 versus the same period 2014. Nationally for the third quarter of this year a 4.4 Bcf a day increase from the third quarter of 2014. So these are real numbers, real occurrences that are happening in the natural gas storage. Woodmet [ph] projects 8.6 Bcf a day growth in electric generation load from 15 Bcf to 25 Bcf. Now renewables get a lot of attention and they should but let me put them into perspective. To be frank about it they’re small and less reliable. Wind and solar combined generated less than 5% of total U.S. generating load in 2014. And an indicative of the lack of reliability again 14 numbers capacity utilization for wind was 34% and solar 28%. Now that should not come as a surprise to anybody of any common sense because we should realize that the sun doesn't shine all the time and the wind doesn't blow all the time but some people have apparently neglected that understanding. But what this really means is that reliable flexible natural gas facilities are absolutely necessary to back up wind and solar. So to sum up the idea that we could move directly from coal to renewables without increasing natural gas usage for electronic generation is an unrealistic pipe dream with the substance and the pipe being legal only in Colorado and Washington State. Now, added to the demand picture is the retirement of more coal plants due to environmental regulations and a nuclear fueled instruments due to age and operational issues and you put all that together and you have a very bullish growth Outlook for natural gas and electric generation. But there are other factors. The second demand driver’s natural gas exports to Mexico. It’s a real and it’s growing. Let me give you the facts. Natural gas exports to Mexico for 2015 are expected to average 2.6 Bcf a day versus a 2014 average of 1.8 Bcf a day. That’s an increase of 44%. This summer we found that natural gas exports had at times exceeded 3 Bcf a day. Over the next four years, Mexico is expected to add 10.5 gigawatts of new natural gas capacity and it's expected that another 3.2 gigawatts of oil power capacity will switch to natural gas. Meanwhile as I think most of us know, Mexico’s gas production continues into decline. Additionally LNG imports to Mexico are on the decline and are expected to be completely phased out by 2023. All of these factors support projections that by 2025 natural gas exports to Mexico are expected to increase from the already elevated levels of 2015 by almost 3 Bcf a day. Third driver is the tremendous build-out of US industrial and petrochemical facilities. Let me give you the facts. The American Chemistry Council now counts 243 projects with a cumulative investment of $147 billion for the years 2010 to 2023. More germane, Texas alone accounts for 99 of those projects with the total value of over $48 billion and most of those are in Southeast Texas which is the sweet spot of the heartland of our natural gas facilities including Houston Corpus Christi and Beaumont. Global chemical demand is expected to double from 2000 to 2040. Wood Mack estimates that over 2.5 Bcf a day of additional natural gas will be required by 2018 from 2015 levels to meet industrial demand driven by these methanol fertilizer and petrochemical projects. Finally let's talk about LNG exports. There are no longer years away. FERC approved LNG export projects have 10.6 Bcf a day of capacity. By the end of this year Sabine Pass Train 1 will be in service with 650 million a day of capacity. By next year with Sabine Pass Trains 1 through 3 online LNG capacity will be 1.95 Bcf a day. By 2019 U.S. LNG export capacity will be 8.97 Bcf a day only counting FERC approved projects which have achieved final investment decision. Now those are the trends that are driving U.S. demand to that extraordinary growth I talked about to 110 Bcf estimated in 2025. Do we have the supply to meet that? The potential gas committee estimated that at the end of last year. The end of 2014, we had nearly 2,900 Tcf of proven and potential reserves and that would be over 100 years of remaining resources relative to the current U.S. natural gas demand. Now in addition to being affordable and abundant, I want to stress again some facts about the environmental friendliness of natural gas. In the midst about half the carbon dioxide emitted by coal and over 30% less than fuel oil according to the EIA. In fact natural gas has been essential to national and regional efforts to reduce carbon emissions. The White House’s counseled economics reported earlier this year -- economic advisers reported earlier this year, and I quote, natural gas is playing a central role in the transition to a clean energy future'. Report goes on to note that since 2007 energy-related CO2 emissions in the U.S. have fallen 10% and a significant factor contributing to the reduction was fuel switching from coal to natural gas for electric generation. On a regional basis I saw New England has stated that as a result of New England’s transition from coal and oil to natural gas from 2001 to 2013 regional emissions of CO2 fell by 23%. Regional emissions of NOx fell by 66% and regional emissions of SOx fell by 91%. Now what I've given you is a lot of facts. But they demonstrate to us that natural gas usage in this country is and will be robust and growing for an extended period of years. And for Kinder Morgan which transports about a third of all the natural gas consumed this paints a very positive business picture for years to come. And with that I will turn it over to Steve.

Okay. And from --- what Rich has just said you can see why we are bullish about the fundamentals that drive our long-term value and I'm going to return to the shorter-term for a minute. I'm going to pick up on what Rich said about being judicious on use of common equity. Because we are generating cash in increasing amounts in our business, we have the flexibility to fund our investments in any number of ways, ranging from self funding them with the cash that we generate, all the way to disturbing our cash to shareholders and accessing capital markets to fund our growth expenditures. We believe our investors value the later, so we have been working within that framework. In a nutshell, what we have been working on and believe we have found is a way to break a cycle which we believe has negatively affected the value of our equity. Specifically, the challenging market for energy commodities this year has bled over to equity values for midstream energy companies. And because we have a significant backlog of projects, growth projects, which is a good thing, we have issued into this challenged equity market for the last two quarters, creating at least a perceived overhang in the market for our equity. We believe in the medium and long-term the market will value our common equity appropriately and we believe the market will value our particular structure that is a simplified large cap C-Corp with a substantial and growing dividend also appropriately. But until that happens, we sought an alternative means to fund our growth capital needs without needing to issue shares in the common equity market for the rest of this year and to mid-2016. That means not having to use the ATM or underwritten offerings or bought deal. It means not having to sell common equity at all for that period. Let me repeat that. It means not having to sell common equity at all for that period. We've chosen the alternative we plan to use and that choice reflects our bullishness on the long-term value of our common equity. And this comes from a management team and board with substantial holdings of common equity. So here's the bottom line for our equity investors. First we're taking off whatever pressure that our common equity issuances were having on the stock. Second, we're continuing to fund our growth projects, but at a lower long-term cost of equity capital than continuing to issue common equity in today's market. Third, we're growing the dividend while maintaining coverage of that dividend. Finally we are maintaining our investment-grade rating, which we believe, positions us well for acquisitions and expansions in this environment. Before turning to the segments and the project backlog there's an issue I'll try to address upfront. When we did our consolidation transaction last year, we projected 15% dividend growth in 2015 with 10% annual growth from 2016 to 2020 and substantial excess coverage over the 2015 to 2020 period. Here's what we expect. We have not started our 2016 budget reviews with the business units yet. But we expect to be able to cover a dividend that is 6% to 10% higher than the 2015 dividend which was 15% higher than last year. As we've said before with what's happened in energy over the last 12 months, the coverage we projected last year in the consolidation transaction has taken a substantial head. Nevertheless, and while projections through 2020 are very assumption driven, we believe we could still have grown the dividend at the rate we have projected last year, however, coverage would've been tight over the period and could have been negative part of the time. Other companies have elected to run at negative coverage, but we believe the prudent decision for KMI and we believe the market is telling us this, is to continuing to grow the dividend but preserve coverage over the period. Again, our underlying business is generating cash in increasing amounts. So for us it's not about finding a way to continue investing in attractive opportunities it’s a question about finding the right combination of dividend growth and coverage and the appropriate alternative financing and we think that in today's broader energy sector that's an enviable position to be in. I'll turn to the backlog in the segments; the backlog first, since the July update, our product backlog decreased by about 700 million from 22 billion to 21.3 billion. We placed almost $400 million worth of projects in service during the quarter, the largest one of which was the second splitter in the Houston Ship Channel which went into service early in the quarter. We added about $700 million for the projects in the quarter, much of that coming from the terminals business unit. We also removed about $1 billion worth of projects from the backlog. The largest piece of which is further reductions in our expansion capital expenditures and our CO2 business as a result of moving some of our EOR and S&T investments outside of the timeframe of the backlog. So, for the segments, in the third quarter, we produced 1.839 billion of segment earnings before DD&A which essentially flat to 2014 and that's a result of the decline in our CO2 segment year-over-year not being fully offset by the year-over-year improvement in our Products and Terminals business segments. For gas, gas was essentially flat year-on-year. We had commodity related volume impacts in our G&P sector. We had a roll-off -- a contract role off on KinderHawk in May, partially offset with -- an additional volume commitment on the Eagle Ford by that same shipper. We have the KML, Kinder Morgan Louisiana contract buyout that took place last year. We're having the effect of that this year on earnings before DD&A and roll-offs on the Cheyenne Plains system. Now those last three items were all anticipated in our budgeting process and we're still on track in gas to slightly exceed the 2015 plan. We had higher transport volumes, up 5% across the segment as we saw a 50% interest increase in power driven natural gas demand year-over-year and 18% year-to-date as Rich mentioned. Sales and gathered volumes were essentially flat year-over-year, Crude and Condensate gathered volumes and the Gas group were up 7% as a result of the addition of the Hiland gathering assets. We continue to see strong demand for long-term firm natural gas transportation capacity. We added 400 a day of firm long term commitments during the quarter that brings the total capacity signed up since December of 2013 to 9.1 Bcf of new and pending long-term commitments. Of that 9.1% it's worth noting 1.6 Bcf of that comes from existing previously unsold capacity. So these signups are adding to our project opportunities but also making better use of the existing capacity that we have. Couple of project updates here, we made great progress during the quarter signing up long-term commitments for capacity on the supply portion of Northeast Energy Direct. We have not yet moved this product into the backlog depending on some further progress on additional commitments. But the prospects for adding this to the NED Market Path product which is in our backlog materially improved during the quarter. We also had good progress on the NED Market Path. We went out with a customized offering for the electric load in New England a much-needed load and much-needed for gas. And we had a few favorable rulings and recommendations in the state regulatory processes including improving our existing LDC contracts and also creating a good opportunity to secure the electric load that we need to make this project very attractive economically. So we continue to see strong demand for existing and expansion capacity on our gas assets and we believe we're well-positioned for the growth that Rich outlined that we see in the years ahead for those markets. We did have a setback on the Elba project we got a scheduling order that slows the regulatory process deferred by four to five months versus what we expected. We may seek modifications to that order to try to improve on that schedule and we're certainly going to look for ways to call back some of that in the project execution phase. Turning to CO2, earnings there before DD&A were 282 million, down 22% year-over-year. For pricing reasons primarily also some volumes reasons as well. Our volumes are down year-over-year by 2% on a net basis now a few more points of that. First, the decline in that volume can be more than explained by a timing issue on Yates. Our net numbers that you see in the release are based on sold volumes. But some of the production in Yates was produced in September, but not transfer for sale until October, the amount of that totally offsets the year-over-year downturn for the whole net production of the group. Second, sack rock was down slightly for the quarter, but up 6% year-to-date and on track for a record year. Finally Goldsmith and Katz were both up year-over-year, but continue to be well below our plan. We had been successful in expecting cost savings in this segment. We continue to forecast reductions in our OpEx and maintenance CapEx of just under 25% for the year. We've also seen cost savings in our expansion projects and it’s demonstrated by the adjustments of the backlog, we are right sizing they spend in this segment in light of the current commodity price environment. Turning to the products group, segment earnings before DD&A were 287 million that’s up 29% year-over-year driven by the ramp-up of volumes on KMCC, our crude and condensate serving the Eagle Ford. The addition of Double H Pipeline from the Hiland acquisitions, improve performance on SFPP, as well as better year-over-year results on Cochin. Also early in the quarter we placed the second of our two splitters in service in the Houston Ship Channel. Volumes are strong here with refined products volumes up 2.5% on our systems year-over-year compared to a nationwide EIA growth rate of 1.5% and year-to-date we’re running a little bit over 3%. We continue to advance our Palmetto refined products pipeline project and our Utopia NGL pipeline project. Turning to Terminals, segment earnings before DD&A were 263 million, up 6% from last year. This segment is the tale of two cities. Our liquids business performing very well both in terms of ongoing business and the growth opportunities while our bulk business has been hit with declining coal and steel business impact of the Alpha Natural Resources bankruptcy on our coal business. FX was also a negative factor for the Canadian portion of our terminals operations. On the liquids side we’re benefiting from higher renewal rates particularly in Houston benefiting from expansions in Houston and Edmonton that we brought online and from additions to our Jones Act tanker fleet. We also announced earlier in the quarter the Philly Tankers acquisition which takes our fleet up to 16 vessels all but two of which are under charter and the other two are in active negotiation even before they roll out of the yard. We announced yesterday a joint venture with BP on about 9.5 million barrels of their refined product storage assets. This is exactly the kind of deal we want to do with companies that have midstream business assets embedded in a larger organization. We believe we can make a win-win here with BP. BP will contract for substantial capacity in support of their marketing activity and then we have the ability to operate and attract third party business, operate this more efficiently and attract third party business to these assets. We look forward to expanding our already productive relationship with them and finding other opportunities like this. Finally for Canada, the segment is down 8 million year-over-year all of which can be explained by FX. The pipeline system itself continues to benefit from high utilization. And the big news as always here at the Trans Mountain expansion project. We received our draft conditions in August, a little bit later than what we had expected. We believe they will be manageable though we did seek some important changes, especially around the time required to approve specific portions of the bill. One of our expert witnesses was hired or appointed to the NEB out of an abundance of caution the NEB ordered us to file substitute testimony which we did in September, but the result of all this was they delayed date for their decision, their recommendation from the end of January 2016 to the end of May, May 20, 2016. We're still working through the full effect of that and the ultimate impact on our in-service date is ultimately going to depend on the final conditions that we receive in May, however we're going to do the best we can here to give you an estimate of the range of that impact and we estimate today a range of in-service dates between yearend 2018 and October 2019. Again there are lots of moving parts here and we're going to be working hard on our detailed project execution plan to optimize all that, but that's about the best guidance we can give you sitting here today on the in-service dates. A reminder also that this expansion is under long-term contracts, which have been approved by the NEB. We're very excited about this project. It’s very good for our shareholders. We're going to get it done, but we are experiencing this delay. That is it for the segment and project updates, so I will turn it over to Kim.

Thanks Steve. Looking at the GAAP income statement first before I move to DCF. On the face of the GAAP income statement, you will see that revenues are down significantly versus the corresponding period last year. But you'll also see that OpEx is significantly reduced. If you net out the certain items that impact revenues and OpEx, the largest of which are the $198 million contract buyout on KMLA in the third quarter 2014 and the CO2 mark-to-market. OpEx was down slightly more than revenue, both in the quarter and year-to-date. As I said the last two quarters changes in revenues is not a good predictor of our performance. We have some businesses where revenues and expenses fluctuate with commodity prices, but margin generally does not. We also do not think that EPS is a good performance indicator. But for those of you who need EPS without certain items for compliance reasons, the EPS without certain items is approximately $0.16 a share. We believe the better indicator of our performance is the cash that we generate which we express in DCF per share in the cash that we distribute which is the dividend per share and so with that I'll go to our calculation of distributable cash flow. As Rich said, we're declaring a dividend today of $0.51 which is an increase of $0.16 over the third quarter of last year. Year-to-date that results in dividends of $1.58, which is a 15% increase over the $1.48 declared for the nine month in 2014. We generated DCF for the quarter of $1.129 billion and 3.47 billion for the first nine months of the year. Both periods are up significantly over the prior year. The prior-year results are fused in transaction closed and so the lot of the benefit in DCF is due to the fact that the MLPs are no longer outstanding. And you can see that benefit in the line entitled MLP declared distribution. I think the better way to look at our results is to look at the DCF per share which takes into account both the benefits to DCF of the transaction as well as the cost of the 1.1 billion shares that we issued to purchase the MLPs. DCF per share is $0.51 in the third quarter versus $0.44 in the third quarter last year which is an increase of approximately 21%. Year-to-date we have generated $1.58 versus $1.29 that we paid or 22% increase. The $0.51 in DCF per share for the quarter results in coverage of about one times in the quarter and for year-to-date we have coverage of well over $200 million. Now there are couple of certain items that I should mention and then I'll give you some details on our full-year outlook. We reported in the quarter $387 million non-cash impairment on our Goldsmith deal, which is in our CO2 segment. Now it’s primarily driven by lower crude prices. The other certain items of any significance to fair value amortization and the mark-to-market, we see those in most quarters and we've discussed them in the past. The only exception is in the other category. It includes a $22 million write-off of receivables associated with the Alpha bankruptcy. The $22 million represents revenues reported in periods prior to 2015. The $50 million negative impact associated with 2015 revenues is shown in the segment. And this is consistent with our philosophy of trying to strip out of our segments prior periods one times and the sporadic cost and benefits to show you the ongoing cash generating ability of our assets. Now the full-year outlook, first, we expect to end the year with approximately $300 million in excess coverage which is below our budget by about $350 million. But let me put this in perspective. That reduction is just 6% of our total BCF and only about 5% of our EBITDA. Now looking through the components of that if you utilize the metrics that we gave you in January, of the $10 million change in DCF for every dollar change incurred and a $3 million change in DCF for every $0.10 change in natural gas the impacts to our results is approximately $235 million. That is a little less than -- that's a little -- that’s approximately a $70 million deterioration from what we expected at the time of the second quarter call due to deteriorations in commodity prices subsequent to that call. As we talked about last quarter our sensitivity assumed a constant NGL to crude ratio. That ratio is actually deteriorated from what we had in our budget meaning that NGL prices have deteriorated more than crude prices. We estimate that impact to be a little bit less than $30 million. The direct commodity exposure accounts for a significant portion of our coverage variance. Lower CO2 volumes, lower midstream volumes and the decline in the Canadian exchange rate on a combined basis are about $100 million impact. So, those items when you add them altogether gives you pretty close to where we expect to end up. Now, there are lots of moving pieces of other moving pieces. We the benefits in interest expense. We've seen CO2 and other cost savings. We've got downsized in coal and steel in our Terminals business. We've lower oil production volumes in our CO2 segment. We've got lower volumes from some of our product assets and we've got lower capital is overhead as a result of reduced expansion CapEx. But all of these other moving pieces essentially net-out to be a small positive. Now, to look at the individual pieces to give a little bit more granularity. We expect natural gas to end the year slightly above budget as Steve mentioned. We expect that the positive impact of the Hiland acquisition to largely be offset by the lower commodity prices and lower gathering and processing volumes affecting our midstream business. We expect CO2 to end the year approximately 15% below and that's actually a little bit more than our commodity price sensitivity would indicate. And that's being driven by lower crude oil volumes, lower CO2 volumes, and lower capitalized overhead, slightly offset by about $43 million in cost savings. We expect Terminals to end the year about 6% below its budget and that's associated with lower coal and steel volumes. The largest piece being the $22 million impact of the Alpha bankruptcy and the FX associated with the weaker Canadian dollar. We expect products to end the year slightly below its budget and there the positive impact of Double Eagle pipeline which was acquired in the Hiland acquisition. Is slightly more than offset by about -- is slightly more than offset by about $20 million of commodity prices on the segment, that's consistent with our sensitivity that we gave you and lower volumes on a number of assets. We expect KMCC to be below its budget by the year due to FX and that's going to be about, we think about $20 million. We expect to have positive variances versus our budget and interest, negative variance in G&A. Those two items largely offset each other. The variance in G&A is driven by incremental G&A from the new Hiland employees and lower capitalized overhead as a result of lower expansion capital spending. On interest, incremental interest associated with the Hiland transaction is more than offset by lower balance and lower rates. Finally, we expect cash taxes and sustaining CapEx to come in lower than our budget, said in another way, we expect them to be a favorable variance versus our budget. And with that I'll move to the balance sheet. We ended the quarter with about $42.5 billion in debt. That translates into debt to EBITDA of about 5.8 times. That is consistent with where we ended the second quarter. We still expect to end the year at about 5.6 times debt to EBITDA. The change in debt for the quarter, there was a reduction in debt about $172 million. And for the full year it's an increase in debt of 1.845 billion. So let me reconcile those for you. On the quarter we spent about a little less than $980 million in expansion CapEx and contributions to equity investments. We made $50 million pension contribution. We had about $7 million in warrant repurchase. We issued equity of $1.27 billion. We had coverage of $2 million and that we had working capital and other items of just over $60 million. Year-to-date the 1.845 we spent about $6 billion this year just under that on acquisitions expansion capital and contributions to equity investments still in our investment program. About $3.3 billion of that was acquisitions, about $2.65 billion was on expansion capital. We made a pension contribution of $50 million. We repurchased north of $12 million. We issued a little over $3.8 billion in equity. We had a tax refund of $194 million that came in the first quarter. We've had coverage of about $228 million and then working capital and other items or use of cash of about $45 million. So with that, I will turn it over to Rich.

Okay. And with that Vance if you come back on, we'll take any questions you may have.

[Operator Instructions] Our first question comes from Shneur Gershuni with UBS. Your line is now open.

Hi, Shneur. How are you doing?

Good. How are you Rich?

Good.

Good. Just a couple of quick questions. You know, I guess if we can start off with your financing plans that you alluded to in the prepared remarks. I guess you talked about widening of the dividend growth range which is probably prudent in this current market environment. But you also mentioned no need for equity into the second half of next year. I imagined excess dividend coverage is part of it but I was wondering if you can elaborate on how you're thinking about it, are you thinking about a convert. Is that something that the rated agency typically scores equity? Any incremental of color would definitely be helpful to understand the financing plans for next year.

Well, unfortunately SEC rules prohibit us from really going into any more detail, but as Steve said, we have picked a vehicle and we intend to implement that.

Okay. Fair enough. I was wondering if we can talk about the backlog next. You've removed some projects from the CO2 bucket, but to also did net add $700 million worth of projects. I was wondering if you can talk about in an environment where we're much longer for lower commodity environment. Outside of CO2 what do you think the sensitivity of commodity prices would be to the balance of the backlog? Is there a price that you're thinking about today that has sort of benchmarks what gets into the backlog and so forth? If you could give us some color as to how we think about that that would be helpful.

Yeah. It's really not commodity-price driven at all. So, what we are putting in the backlog outside of CO2 which is a little bit different. I'll come back to that in a second. What we're putting into the backlog are things that we have contracts on and we're waiting on a permit. Some of the stuff that's in the backlog is already under construction. We just don't have revenue yet because it having gone into service. So, these are high probability projects that are secured by contracts for the customer is really taking the risk on what the volume is going to be and what the commodity price is going to be ultimately. So, these are really with the exception of CO2 which again I'll come back to these are midstream assets were people are buying the space from us and securing and under contracts and then we go get it approved and build it. And if we think it's a high probability that it gets done, it makes into the backlog. That's really the criteria. It's that probability of completing it and getting revenue from it for our investors. CO2 -- and I have said this before when we have talked about additions to the CO2 backlog in the past in a different commodity price environment. CO2 is programmatic spend. Right? It is driven more by -- we are going to invest in this development or we are going to invest in this expansion, because we think the pricing is there to support it. And we try to be conservative in the pricing and all of that. But that’s a little bit more programmatic and therefore is more driven by commodity spend -- or commodity pricing. Now, the other thing that’s going on in CO2 this year that you will see is that the S&T part of our business, we feel like we've got -- we've got a much smaller CapEx plan that we need in order to meet the demand for CO2 as we see it. And so we've scaled back investments, for example, we talked about the Lobos pipeline earlier. We had talked about the Cortez pipeline, which we're proceeding with in part. We've scaled back that to deal with a current flattening of demand, call it, in the CO2 environment. The other thing that’s happened in a CO2 is that we've had good results on the projects we have proceeded with. So for Cow Canyon, for example, we were not even quite halfway into our drilling program. We had very good results and we don't see the need to finish that program until we see additional demand. The additional production that we got from the first six wells or so was enough to take care of what we think we need. So that’s how the backlog shapes up. You've got to separate CO2 from the other midstream parts of the business and those are contractually secured.

Just one last question if I may, you talk about the backlog being contracted and so forth. I was wondering if you can remind us of your customer breakdown. If I remember correctly you're not that linked to the producers and it's more to utilities and industrial customers. I was wondering, if you happen to have that breakdown of customers on hand as to how it looks in your backlog and legacy business?

Yes. There are a couple of ways to get at that. I mean, first of all we have a very broad customer base. So we have very few customers that account for even more than 1% save our revenues. So we’ve got utilities. We have producers like BP and Shell are very large customers of ours, Utilities our large customers, the refiners, the integrators all of them and producers and LNG. So we’ve got a very broad group. The other way of looking at it is just kind of where our growth is coming from. And I think in this 9.1 Bcf I think there's about -- I'm talking about the gas side now. The 9.1 Bcf of what we've signed up. About a third each goes to LNG and producers and then the other third is made up of utilities and Mexico. So that's how that breaks down.

Great. Thank you very much.

Thank you. Our next question comes from Brandon Blossman with Tudor Pickering Holt and Company. Your line is open.

Good afternoon.

Good afternoon, everyone. I guess, Steve to get back to the financing question in the alternate forms. Won't hit on that specifically, but you have a plan for the next call it nine months plus. What do you need to the change -- the answer is probably pretty apparent but what you need to see in change in terms of common equity to be comfortable going back to that as a form of financing. It is just a yield program problem or is it a depth or liquidity problem for the common? A - Steve Kean It's not a liquidity problem in any way, shape or form. We're very liquid security and the market has a significant appetite for the security. So, it's really more the cost of equity capital to us and what we believe we're seeing Brandon is a temporary situation where the cost of that common equity is higher than, at least in our opinion our judgment, higher than it should be. And it has created a situation where we can access alternative forms of capital at a lower long-term cost of capital for this interim period whatever it turns out to be. They once need particular magic in doing it to mid next year other than to communicate to you and all the other investors out there that we have options and we can stay out of the common equity market for a significant period of time. So, there's not a magic number that we have in mind to come back and it's really going to be more driven by the cost of our available sources of capital and I think we're going to be demonstrating to you that we have flexibility in that regard.

Thank you. That's actually very helpful. And then on the project aside, Northeast Direct, is it fair to make the assumption that the power product for the demand side of the project was tied to the Massachusetts ruling and is it necessary for other states to kind of have a similar ruling in terms of allowing gas supply into the power gen rate base.

That's just thrilling, it very positive obviously. Beyond that, Steve.

I will start and end time can fill in too. So, what we call the PowerServe, the offering that’s specific to power generators or the power market, let's call it, predated the Massachusetts order. But the Massachusetts order was very affirming in that regard, we believe. It’s the recognition of and the need to provide a mechanism for approving and recovering the cost associated with the needed upstream firm gas transportation capacity. So those things go very much hand in glove in our mind. Other states will be doing their own processes to figure out how they are going to approach the securing of the contracts they need for their power generating sectors. But we're very optimistic about that. Now having said that, we're not going to come back next month and expect to see a whole bunch of the power loads signed up. We think this is going to take time, because these things are processes. What Massachusetts is going to do is they are going to expect, I think, utilities to go out with some kind of a competitive process. And so it will take us some time. But we are very -- we're delighted with the steps that have been taken so far to put us in a position to place more of this capacity in the service of the power sector. Tom?

Yeah. I guess the only thing that I would add to that, Steve, is that New Hampshire was also very positive in their PUC process and comments about natural gas and the need for additional infrastructure into the region. New England ISO has been very positive along the way needing -- dating if there's needed additional reliability with the electric grid in this area by adding additional infrastructure. And we can't say a lot about the open season process, but I think there is interest in debt that’s showing consistent with, kind of, the trend of showing a need for an incremental infrastructure into the region. So I think there have been some very positive developments here over the last quarter.

And look -- let me just pound the table one more time on this issue. Just in the past few weeks you’ve had another nuclear facility announced that its closing down. The thought is that there will be a second one. And that's on top of one that was already scheduled to be shut down. You can't take 500 or 600 megawatts out and expect not to be able to use natural gas to fuel your needs for electric generation and the idea that somehow a swan is going to swooped down and deliver wind power or solar panel in the next few months or years even to New England is just not facing reality. And the only practical choice in our judgment and it's a mix of a lot of things but natural gas has got to play we believe a major role in generating capacity in New England. And this is the whole underpinning of the whole Northeast Direct project on top of the very nice LDC demand that we have already buttoned up.

Yes, okay. So moving in your favor I understand that there are many sunny days in the Northeast as one would like. And just finally real quick $630 million a day on the supply portion of Northeast Direct actually is in my mind a surprisingly large amount but it sounds like you guys are still looking for more on that side of the project?

Yeah, we’re kind of -- we’re still a little bit early in getting some of the LDC piece of that. So that’s really it’s kind of a producer push and some local significant local power demand and a little bit of LDC. But we think there is more of the utility load coming and so we're actively working on that and think we'll get some of it.

Yeah. Who know a lot here more over the next three or four months.

Okay. Thank you very much guys.

Thank you. Our next question comes from Darren Horowitz with Raymond James. Your line is open.

How are you doing?

Hey, fine. Thanks Rich, hope you and everyone are doing well. Steve couple of quick questions. The first to the extent that you can answer. With regard to lowering your long-term cash to capital, can you just give us even if it's a rough quantification the magnitude of cost to capital savings that you guys have penciled up with regard to reinvesting free cash flow versus the issuance of common equity burden by multiyear dividend growth ahead? Am I'm just curious venue did the analysis of that cost of savings, was it more built of the extrapolation of 6% to 7% annual debt growth through the end of the decade or what was the duration and how much do you think you can save.

Unfortunately Darren I cannot get into those specifics. But I think I can say that it was a substantial savings and enough so that we are prepared to execute on it.

Okay. Well, if I could just shift gears back to in your prepared commentary about being flexible for the opportunity of third-party assets. How do you think the Northeast infrastructure supply/demand dynamic changes not just the rear depending that is out there and maybe the impact on either commercializing the supply portion of NED or maybe commercializing the revised scale or scope of you and PT but am also thinking about any sort of opportunities that you guys see from a demand pull infrastructure perspective, maybe some logistical opportunities. Maybe some with increase residual value that gives the opportunity to leverage our refined product business or your terminal footprint. Any commentary there would be helpful.

I think there are lot of opportunities and I think that as we've said so many times, having the footprint and the diverse assets that we have is a big plus in working out those kind of possibilities. And so obviously we see a lot of upside and a lot of potential. It doesn't take -- everybody is aware of the fact that you've got a whole bunch of gas and liquids basically being underutilized or underpriced coming out of the fastest growing, producing region in America. And getting those to the most needed market or where the greatest need is, New England is the first priority. But as we've said all along, we've reversed size proportions of Tennessee system to get it back down to this area to serve LNG load, the petrochemical load that I referred to. So there's just a whole bunch of opportunities for us. And I think as we build these new projects they will lead to additional opportunities just as the Tennessee system has led to all these opportunities over the last couple of years. Tom anything else on that?

No.

Thanks Rich.

Thank you. Our next question comes from Mark Reichman with Simmons & Company. Your line is open.

Hey Mark, how are you doing?

Good. Just a quick question on the rating agencies. I think on the last call you -- it was mentioned that they were willing to live with the elevated credit metrics until Alba and Trans Mountain were starting to contribute which would show some improvements in the credit metrics. And I was just wondering now that it looks like both of those projects are experiencing some -- maybe some modest delays to the schedule, what have your conversations been with the rating agencies and how they in terms of what they are kind of looking for and timeframes for living with an elevated credit metric?

So, this is recent news both on Trans Mountain and Elba, but with -- if the projects get pushed out, so does the spent. And so what’s driving the leverage to stay high over time is the fact that you're spending dollars with no cash flow coming in. And so I believe will be able to manage through that.

And so that kind of maybe plays into managing spending and retaining more cash flow to fund growth as well as to deal with the weaker fundamental environment?

I don't really think about the projects and the project delays being linked to our decision to go to the range or to look at coverage. No.

Okay. And…

Let me just say again, just to be very clear on the range. As Steve and Kim have both indicated, we’re just at the beginning of our budget process for 2016. So we're just giving you a range. It doesn't mean it won't be 10%. We've given you a range from 6% to 10%. And we are going to be very judicious about how we approach the whole situation. But it is a range. It’s not excluding the upper end of the range at all. So I think that's important to keep in mind as we move forward.

Thank you. That’s very helpful.

Thank you. Our next question comes from Kristina Kazarian with Deutsche Bank. Your line is open.

Hey guys I appreciate, so can you guys just talk a little bit maybe help me get some clarity around the decision to lower the bottom end of the range to 6%. How did you settle on that number and then what it implies for the longer-term range that we people have been using on 17%, 18%, and 19% if there is anything there.

The 6% to 10% is just the uncertainty that we have the before we go into the budget process and wanted to make sure that we're going to be able to fulfill that and also aim for an appropriate amount of coverage. And in terms of kind of the longer range I don't know how much you can really read into that. I think that you have to look at all of the kind of twos and froze within our underlying assumptions. If you go back to where we were when we announced a consolidation transaction and just try to examine what has changed over that year. I mean certainly the one thing that's a negative that we talked about at length has been a change in commodity prices that direct and indirect impact of that. On the plus side, we had a much improved tax depreciation benefit and attacks depreciation number from what we had when we originally rolled out the assumptions around the consolidation transaction. Such that we know feel pretty confident. We're not going to be any kind of a significant cash taxpayer until 2020. If you think about the other things of that we're moving at the time, we also I think we projected some capital spend. I think we have been physically on track on the amount of capital that we've deployed although we do have some pluses and minuses assisted with project delays or we have some minuses associated with project delays. So I think we've been able to find plenty of opportunities to invest in the capital. And then, try and think, there's one other factor in there that built into -- we did not include anything for acquisitions. So we, I think, had a couple hundred million dollars and we had some small, kind of, tuck-in acquisitions assumed at the time and if we did any significant -- one or two significant acquisitions over the time period that would be potential upside to those numbers. So…

I was going to say -- when I think about it historically that normally gives me the budget update, I think, in December. Do I think about from a long-term perspective maybe I get an update in December, do I get it what's like the next Analyst Day. How just roughly should I be thinking about this?

Generally, we have updated our guidance in January. But I think go back to what Steve said at the beginning, which is, when we did Fusion, we believe we could grow at 10% per year and we had substantial excess coverage. And what we're saying today is that the deterioration in the energy markets have essentially taken away a lot of that excess cover, so some of our flexibility. And so we could still choose to grow at the 10%, but coverage might be -- could be -- we don't know projections and very assumptions could be very tight and so we're just going to give ourselves the flexibility as we go forward to decide on how much coverage and how much to grow.

Really helpful. And then just lastly when I'm thinking about your target leverage level for year end. I know we talked about the 5.6 times. How do we think about that number for, say, like 2016, 2017? Like, what's a longer-term target I should be thinking of?

In terms of the debt to EBITDA, I think what we have expected is to run at the higher end of the range 5.6 for a number of years until we get the -- until we get TransMountain some of the other projects on and then we would expect that to decline to the low five.

Okay. Thanks guys. And I appreciate your market commentary at the beginning. It was really helpful.

Thank you. Our next question comes from Ted Durbin with Goldman Sachs. Your line is open.

Ted, how are you?

Hello Rich, doing all right. I guess, I hate to be the dead horse but the coverage issue is really what I'm kind of focused here and it just feels like moving 8% to the midpoint for 2016 how do we think about that on a multiyear basis. You historically rank KMP pretty tight on coverage. Are you saying that you think because of the lower for longer environment coverage needs to be wider. I am just trying to get a sense of where your head is on coverage?

So again I think what we’re -- and we think the market is telling us of this that, where things are valued right now and at our current equity yield, it doesn't appear that people are really valuing the growth in dividend so much as they are kind of some stability around that. And so what we are trying to dial into here is to make sure that over the period over the next several years we have a growing dividend and really a substantially growing dividend because the underlying cash flows in our business are growing, but then we dial in appropriate coverage on that. And so we're going to be striking that the balance as we go but that’s I think the message we are hearing from the market and that's what we're acting on.

And I think another important factor is we're continuing to generate the cash flow. As I said, if we want to grow at 10% we can grow at the 10%. So, what I think people ought to be concerned about is what's happening in the underlying business. And then we can make adjustments as we understand what the market value. So, if the dividends are more important, we can pay those out. If is more important to have some flex ability than to have coverage then we can do that. So, I think -- and let me just say we've been saying for a number of months now that the coverage has been substantially diminished versus the time we did fusion because of the dramatic change in commodity market. But -- and so, what we are saying today is no different with respect to what's happening underneath to our assets. All we're doing is telling you how we're going to be flexible in the future with respect to the dividend.

Understood. And I guess then again thinking through then the backlog and how you are thinking about the hurdle rates on projects. Does -- I guess what you're saying is you're not happy with where the evaluation is in the equity they changed at all the investment criteria you're using around CapEx?

We still in every project that we pursue, we're looking to get the highest possible return available in the market. That really hasn't changed. Now, when it comes to the cost of the capital -- so all of the stuff that's in our backlog is accretive. It's beneficial to our investors even with today's elevated yield and elevated cost of capital. And obviously cuts into it a little bit the longer it lasts but are still very attractive investments even at our current cost of capital. And will continue to be very judicious. And we are constantly reviewing among us and the business unit Presidents what our cost of capital is, on a long-term basis what it is, on the near-term basis, and making sure that we are being very careful to get returns that are an attractive premium to the cost of capital that we're incurring.

And then the last one, I think I heard a comment, Steve, you said you don't think you're not going to be a cash taxpayer until 2020. I thought the number was more like 2017 or 2018. What changed there, that that's going to be up?

We now anticipate we will not be a significant federal tax payer -- cash tax payer until 2020. And that as Steve was saying, life in general is a mixed bag of things positives and negatives. And with return to -- in terms of the product Fusion what happened was, the negative obviously when we did that, we have the commodity price forward curve much higher than it is today. Somewhat offsetting that is the fact that the cash -- the tax situation has improved and we've been able to extend the period during which we would not be a meaningful cash taxpayer. So that is a positive.

Great. I'll leave it at that. Thanks.

Thank you. Our next question comes from Jeremy Schmidt with JPMorgan. Your line is open.

Good afternoon.

Good afternoon. How are you doing?

Good. Thanks for the color today. I was just curious about the -- this vehicle that you talked about, that you can't give too much color on right now. When would you be in a position to tell us more? Is there any timing -- timelines that you could share with us as far as when you could tell us more about it?

No timelines. I'm afraid it's as straightforward as you will know it when you know it. And everybody will know it at the same time.

Got you. And as far as this vehicle was concerned does this improve leverage or does it just keep you out of the equity markets. Is there anything that you can share with us on that?

Think the only thing for the general things that we already said which is what we are fundamentally trying to manage to. One is accessing the capital markets what we think is on a long-term list cost of capital available today, right basis. And second is maintaining investment grade rating. And third of course it should of been first is maximizing value to our shareholders and so that’s really the criteria that we used to evaluate among the alternatives that were available to us.

Got you. Great. And then just one last one it's really early in the process and I know obviously commodity prices have been a big part of it just wondering when you're thinking about 2016 guidance and you talk about some uncertainty there that could drive dividend growth within that range of 6% to 10%, what are the other factors you see that her big variables that could push the results toward one end or the other?

The reason again for the range is just that we haven't gotten the specificity yet that we need to really be able to answer that question. The things that drive our business typically when we get into the budget process is a big focus that we place on costs. That focus will be there again this year just as it always is, want to operate safely but efficiently. The impacts - the year-over-year impacts of the projects that have come online in 2015, the year-over-year impacts of contracts that have renewed, our assumptions about future renewals during the year and there will be pluses and minuses across the whole network that we'll be taking into account. We think that for a business of our size, it's remarkable that we can call our shots really as well as we can and that's a function of the underlying stability of our business and we've historically been able to be very tight about our projection and put together a good budget. But those are the drivers that we look at really every year.

Great. Thanks for that. And then just one last one if I could. Just with regards to M&A out there, how do you guys to see the market at this point in time and does this vehicle preclude you from doing anything in that arena?

It certainly doesn't preclude us, but I'll let Dax Sanders our VP of Corporate Development talk a little bit about the M&A market.

Yeah. Just give me a little flavor of the market and I kind of break the market into three buckets based on value. With respect to asset deals and kind of what I call low to mid nine figures are called a few hundred million dollars I think we're starting to see some opportunities. We have the just announced the BP deal and I think we're going to find some more deals over the next six to 12 months that are similar in size. There are no guarantees, but I think there's going to be some opportunities to do one or more deals in that range. They don't necessarily move the needle as much as larger deal that are nice investments nevertheless. You move up a little bit, it’s a potential asset deal, single asset deals that are in the plus range with have continue to evaluate deals in that range and have looked at quite a few easily, but we're really just haven't to gotten their own valuation. I think the bid off the spread issue that's so often discussed is persistent there. When taken into account some of those expectations on price and just the risks inherent that we simply haven't seen situation where we wanted to pull the trigger and I really have no idea when that is going to change. With respect to larger corporate deals, who knows, as always those types of deals are much more difficult to do generally and especially to predict when they might be done. And of course regarding any large deal we have to make sure that our shareholders are rewarded for going down that path.

Yeah. And nothing in what we're planning -- nothing, and as I said at the beginning, what we are trying to do including by maintaining investment grade rating is keep ourselves in good position to access that M&A market for opportunities that are attractive to us.

And anything on the international side of interest there, really kind of a North American focus?

So far still a North American focus. I mean, would have to have really superb attractive returns to go outside of North America, I think, and we see plenty of continuing opportunities in North America. But, again, as we've said, knowledge and the fact that we're no longer an MLP means that it gives us more ability, more flexibility to do projects outside of North America. But again that would have to be very high return projects for us.

Very helpful. Thank you.

Thank you. Our next question comes from Faisel Khan with Citigroup. Your line is open.

Hi Faisel. How are you doing?

Good. How are you doing Rich? Thanks for the time. Just -- Dax, going back to your comments around M&A. I appreciate you just putting it up into three different buckets. On the third bucket, the large corporate M&A, are you saying that the valuations still don't look attractive or is it -- you've seen a lot of carnage in the MLP and midstream space. I'm just trying to understand, sort of, what your view is on the value, the corporate that sit in the market today.

Yeah. So by the third bucket I assume you mean the large unit, you know, as we always say you’ve got to have three things. First, you got the lumpy assets; you have to convert the three things. First, you got the lumpy assets and then you got to have the evaluation and then you got to have the social issues. You’ve got to have sort of the perfect conversions of those three items to make a deal happen and obviously we can't comment on any specific situation. But I think probably any situation you can -- have it three of those converges is just extremely difficult and extremely difficult to predict when that's going to happen.

Okay. And in terms of sort of financing your growth I mean, if you look out in the debt markets today what's your preferred sort of mode in terms of financing your capital spending, is it through fixed floating or and how your debt issuance costs look today versus where they were six months ago?

Yeah, so we're going to find in order to maintain investment grade. So whatever mix of equity and debt that we need to do to maintain investment grade. Typically on new issuances we are funding on the debt side about 50% equity and about -- about 50% fixed and about 50% on floating. So we’re about 25% floating overall right now and that's just because when we did El Paso that acquisition came with a lot of fixed debt. But on an ongoing basis typically we're swapping about 50% of our debt.

Okay.

Floating…

Okay. Got you. And then on the cost as your debt issuance cost remain roughly the same over the last six months but it seems some issuers sort of see their spreads blow out a little bit even though their investment grade?

Yeah, our spreads have widened some but the treasury has come down a little bit as well. So it is a little bit higher today than it was six months ago.

Okay. Got you. And as I'm looking at your guys backlog of $21 billion so what is the procurement plan in that -- for that backlog of for steel and pipe and other materials. We've seen the stronger dollar and we've seen the steel costs come down. So, what's the plan to try to reduce the cost of that backlog and sort of increasing returns or is there a plan to sort of look at that?

Well, there is always the plan to get everything for -- get it as cheaply as we can and to maximize our return by only spending as much as we have to and only spending at one we have to. And so, we do that kind of on a project-by-project basis and Faisal, it is really a mix of things across the spectrum. Sometimes we will get steel trackers that are negotiating because that is a variable commodity and on a lead-time project, you're not sure what it's going to be when you get there. We've gone from having steel trackers. We have done some preorders. We've done a variety of things and its really pretty situation-specific, but we're very focused on fighting the lowest-cost provider and reducing the spend as much as we can and managing it as close to when the revenue when the money starts to come in as we possibly can. And if anything I think we're putting even more focus on that then we have historically. It's just we're watching all those things very closely.

And to go back to your question on debt issuance. I think it would be a little less than 100 basis points more expensive today than it was at mid-year.

Okay. Got you and then just on the backlog, so does that incorporate sort of where steel costs are today and where they were sort of six to nine months ago?

We keep those things up-to-date. We review our major projects every month. And we also -- at least once a quarter, we go through the -- what our procurement group is showing us as the price per horsepower, the price per a ton of steel, the price for various diameters of pipe et cetera. So we're tracking that pretty closely and every month we're asking, do we have cost savings. Are we starting to see contractors cut their prices because they're desperate for business, same thing with equipment providers, material providers and the rest of it and is it a mix. Things are still pretty active in Houston and so we are not seeing much in the way of breaks there. But there are other places clearly where contractors are getting hungrier, particularly in the CO2 business, but also in some of our other assets. So we're -- we’re just -- I don't know how better to answer it than to say we're very much on top of it.

That’s fair. I appreciate the time. Thanks guys.

Thank you. Our next question comes from Craig Shere with Tuohy Brothers. Your line is open.

Good evening, folks.

How are you doing?

Good. I appreciate the call and keeping it going little longer here. Sorry to beat a dead horse. Did I understand the answer to Brandon's question about this alternative vehicle and the timing through not only second half this year, but first half next year as just being, we got to pick some point in time and this could -- we could really differ the equity issuance on an ongoing basis beyond that. We're picking this point in time to start. Is that what I thought I heard you say?

What we are saying is that we have mapped out a plan to avoid the necessity of going into the common equity market through the middle of next year -- rest of this year and the middle of next year. And beyond that we will take a look at what we want to do beyond that. But again as Steve said just looking at this with the kind of yield we're trading at right now it just didn't make any sense to us to continue to have that overhang out there on issuing common equity. And so our view is to take that off the table, and longer-term and most importantly achieve on the long-term basis a cheaper cost of equity financing.

Okay. I’ll let it go at that.

I'm sorry, we can't share more with you, but our General Counsel is sitting across the table from me. So, we just can't say any more under applicable rules without being -- we don't want to be front running anything. So as Steve said, you’ll know I think soon enough and we'll go from there.

Okay. And did I miss any comments about potential workaround for Palmetto given the Georgia decision in May?

I can touch on it briefly just that we continue to make progress on that project we believe it has a real value to Georgia and Florida consumers and we have customers for it signed up. And so we are pursuing our appeal of the Georgia DOT decision. We believe we've demonstrated the need that our customers certainly have by having signed up the contracts that they did. And so we continue to make progress on it and continue to pursue it and believe we'll get it done.

Okay. And that's helpful. It's understandable that the EOR investment is coming down and some of the CO2. My question with SACROC kind of the lowest level now since third quarter 2014, we had a little drop this quarter. What if this goes on for what have you another three to six quarter and then energy prices come back a bit and make some more sense to make investment, does the delay in ongoing investment impact the ability to get value for the same dollar out of the field?

I'll ask Jesse to answer that, our CO2 President.

I think the reduction in SACROC is a performance issue, not an economic issue. We'll continue with the current prices to develop the field. We may have a temporary lull in production based on area in the field, but we are moving from outer field to improve production. We're not pulling back on existing CO2 area in SACROC or Yeats or any [Indiscernible] at this point all economic of the current market.

And we're not slowing down, but slowing down wouldn't leave oil -- we couldn't go back and recover.

And it can always be recovered.

I think it's important to put this into perspective that we expect for the year -- Jesse correct me if I'm wrong, but to set all-time records for oil and NGL production in SACROC.

That's correct.

It's a positive story in our view. Not a negative story at all. But where we have cut back and Steve has made this point I think where we have cut back as we were getting ready to ramp up the significantly to supply more CO2 to the market to our third-party customers. And as prices of the commodity of the crude oil went down so much, we're still maintaining where we were in terms of demand for CO2 but we did not need to ramp up as quickly and that’s mostly where the capital reductions in the CO2 segment have come from.

And while we're on the topic, I think the press release gave the very first disclosure for the early rise investment. I think that was kind of alluded to as potentially being big long-term in your last Analyst Day. I understand that there's a major hurdle given where commodity prices are right now. But can -- given the early indications of this, are we on track to get anywhere close to kind of stimulation that you were hoping for. If we had $6 oil prices again, could this be as big as was discussed previously?

Jesse?

Yeah. We still maintain a positive outlook. The volume, metrics, all the early indications are positive. The processing rates are little slower, but we're implementing a plan to speed that up. Phase II at this point seems economic. It is economic. Going forward into Phase III and IV, as you start putting in more facilities, the processing were to play in to that. So we still believe that that’s a viable project long-term.

Okay. Thank you.

Thank you. Our next question comes from Becca Followill with U.S. Capital Advisors. Your line is open.

Hi, Becca, how are you?

I am good. Thank you. On Trans Mountain, can you talk a little bit about whether or not the -- with the push-ups the cost has changed and is there any kind of provision in there for the customers that it has to be done by a certain time or they have out in their contract?

Well, we have Ian Anderson, the President of Kinder Morgan, Canada here and he was waiting for the question. So…

Sure. Thanks. You made my trip down worthwhile.

I am so happy.

Let me answer it this way, as far as the cost go, we’ve been reporting US$5.4 billion for the project for a number of quarters now and that is still a good forecast. The project was originally filed with the regulator as CAD5.4 projects if you convert the 5.4 American that’s about 6.8 Canadian today. And a few things have driven that both some scope changes to the project foreign exchange on non-Canadian source materials as well as the impact of the delay. So we add those three factors together the project is currently sitting on about a 6.8 Canadian forecast or about 5.4 U.S. that we have been reporting.

Thank you. Thanks. It is fair to add them both from the standpoint of cost parameters and timing parameters we are well within the bounds of our contracts with our customers.

That’s right. Contracts with the customers contemplate $6.8 billion capital to the project under which they've got no ability to de-contract their commitments so we're at that now and we're not hearing any pushback from shippers at this point in terms of their contractual commitments. As far as the timing goes the only timing out that there is it that we don't have a regulatory decision and approval by the end of 2017. We'll be well within that. The regulator is going to issue their decision as Steve pointed out in May 2016. So we're well within the bounds of all the contract commitments we have both from a cost standpoint and a timing standpoint.

That's very helpful. Thank you. But just to clarify so if it does go over the $6.8 billion cap that provides the out for some of the customers.

If we present a toll to our customers that is reflective of a cost in excess of 6.8 that gives them the out.

Okay. Thank you.

And that's an important distinction.

Okay. Thank you. And then on your Northeast pipelines not so much the Northeast Direct with some of the other pipelines that are more producer driven, some of the producers it now have a lot of access ST. Any pushback with some of the customers to say, well I signed up for the contract, but I don't really need it now and can you let me get out of it or can we defer the timing of it?

I think we are seeing incremental interest for capacity declining to some extent in some areas. But clearly any commitments they've made the date we're standing behind and we're not seeing any issues in that regard.

But no producers have approach you to maybe push things out?

Not to this point. No.

Okay. And then finally on Aldo. What is the timing for an FID on that?

It's already FID.

It is FID. So I think as you get the final FERC approval, it's good to go.

Okay. Thank you guys.

Thank you. Our next question comes from [Indiscernible] with Hartz Capital. Your line is open.

Good afternoon, or maybe you I should say good evening everyone. Quick question, a little bit out in left field. I was just curious on TransMountain any other ideas you have brewing up there in Canada, with this week's election how that might impact your thinking or your operations up there knowing that you have a 100% controlled governments now by the Liberal party up there?

I’ll let Ian answer that.

I am wearing my Liberal red tie. It's to let early to speculate what a Liberal governmental is going to mean for us. We're going to continue to focus on the NED process that we are involved in all of the requirements of this while we continue our project planning and preparation. We will certainly be briefing the Liberal government in due course on the project and the progress we've made. But I don't yet have any comment on what a Liberal government may do to us with respect to the project. We will just keep working very hard to keep them informed and plan to execute the project as soon as we get approval.

Great. Thank you very much.

Thank you. Our next question comes from John Edwards with Credit Suisse. Your line is open.

Hi, John. How are you?

Doing well, Rich. Thanks. Just if I could on the dividend growth outlook and knowing the past you have indicated kind of a fill-in amount of capital expenditures to meet the longer-term objective. And if memory serves me I think it was something like I want to say six -- it had been like a 10 and it came down. And with the revised kind of growth range, what -- how should we be thinking about what kind of fill in capital projects would be needed to meet I guess -- the new objectives?

I think you should think we're -- capital objectives that we'd always had John, and as Steve said earlier, we are on track to do that with our backlog with what we've already brought in service if you didn’t look at what our original goals were for Project Fusion. We're tracking that pretty well. It's the commodity price that has been the negative in the Project Fusion assumptions. So I don't think you would read anything into this that our capital program would change and we are still looking to continue to grow.

Okay. And so then, so longer term should we be thinking about a range six to 10 longer term range or kind of paralleling 16. Is that correct?

Okay. Let me, I’m…

Sorry, Kim, I know it’s been -- you’ve gone over it a bunch of times. Just to be clear.

I'm going to try one more time.

Okay.

So, '16 we haven't gone through our budget yet. But we're giving ourselves a range because we haven't been through the budget. There is a fair amount of uncertainty. We know people are going to want an update. Over the longer term what we think, what we -- I said earlier is we did fusion, we thought we could grow at 10% per year. We had a substantial excess coverage. What this energy market has done is it has essentially depleted that excess coverage. And so now we think that we probably can't grow at 10% longer term, but that the coverage would be very tight and could be negative in some years. And so what we’re saying is that as we go forward, we are going to have to look at what our coverage should be and what the dividend should be given that the coverage has been depleted. But the underlying business can still achieve the 10% growth. That is why Rich I think the capital assumption could not change the underlying assumptions in terms of the capital spend have not change on some of the volumes have deteriorated but oil price has deteriorated and that is what is driven the depletion in coverage.

Okay. That's very helpful. And then just lastly I hate to keep coming back to this, but just in terms of modeling the alternative financing. I mean should we be thinking about this as equity, as some kind of preferred, some kind of debt, or can you not to comment at all?

We can't comment at this time.

It is equity. We have said that.

Okay. All right. And then lastly on Trans Mountain. Just to follow-up this question. There's only a cost up there is not a timing out. Is that correct?

What I said is there is a timing out if we don't have our certificate from the federal government and the regulator by the end of 2017.

Okay. Great. Thank you. That's all I had. Thank you.

Thank you. Next question comes from Corey Goldman with Jefferies. Your line is open.

Good afternoon.

Good afternoon. How is it going?

Good.

Just a quick follow-up on Craig's question earlier about Palmetto. I think Steve last quarter you talked about how the DOT approval was not essential. Is that still the case or are you kind of going to the appeal process and take it from there.

It is not a requirement that we have public a certificate of public convenience and necessity from the Georgia DOT but our appeal is about considering to pursue that.

Got it. And then Kim is there an update to the hedges on the CO2 side that we can get?

Sure. On 2016 we're about 63% hedged at $72 a barrel. 2017 is about 58 at $73 a barrel. 2018 is 45% at $75 a barrel and 2019 is 24% at $66 a barrel.

Got it. That's really helpful. And then just the last one for me, it looks like natural gas pipelines just turning a little bit above what you guys were expecting and it sounds like a portion of that is attributable to Hiland, can you kind of talk about how the ramp is going there and how that's gauging versus your initial expectations when you first closed in February?

Yes. I think it is probably -- it’s very close but probably just slightly under what we had anticipated for this current year. Now when we put our projections together for Hiland we gave them -- we gave the solar projections a pretty good haircut and we didn't assume low price recovery really at this year or next. And so we gave ourselves some pretty good running room there. I think probably a little bit under on the revenue side and a little better on the cost side. That includes just operating costs, maintenance capital, and financing costs. We looked at it a couple of months ago and we were just a little bit over. I think we're now just a little bit under.

Great. That's really helpful. Thanks guys.

Thank you. At this time, we no longer have any questions on queue. I’d now like to…

Thank you everybody for bearing with us for an hour and a half of informative questions. And thank you and have a good evening.

Thank you. So that concludes today's conference call. Thank you all for participating you may now disconnect.