金德摩根 (KMI) 2015 Q3 法說會逐字稿

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)

I would now like to turn the call over to Mr. Rich Kinder, Executive Chairman of Kinder Morgan. Thank you. You may begin.

Thank you Vance. Before we begin I would like to remind you that as usual today's earnings release and this call include forward-looking statements within the meaning of the securities 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 for look at image.

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 will turn 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 will take any and all questions that you may have.

Let me start right reviewing our 2015 performance. We raised the dividend for the third quarter to $0.51, and we expect to achieve our target of declaring $2.00 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.

That is less coverage is in 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.

But I promise it to put things in perspective. And let me try that. If you take our $2.00 dividend and multiply it times 2.2 billion shares outstanding, that's $4.4 billion of cash distributions to shareholders of that we will make for 2015. If you add to that $300 million in excess coverage, that means $4.7 billion of free cash flow after payment of all our operating expenses, our maintenance CapEx, interest on our debt.

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 elect to distribute the bulk of our free cash flow to our shareholders and then pay for our expansion CapEx with a 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.

Let me also put into perspective our business and its prospects for the future. I talked about our 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. That phrase, though, happens to be very true.

But I want to give you some hard cold facts about the natural gas storage, 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 is abundant, cheap, domestic, and clean and that is all true. But I thought it would be interesting to give you some actual factual detail on what is really happening on both the demand and supply side of the natural gas story because it is so important to us, and to other midstream companies. If you compare 2014 to 2015, Wood McKenzie is now estimated there will be an increase in demand year-to-year of 5%. It is projected to increase from today's level of 76 BCF a day to about 110 BCF a day by 2025 - that is 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 2015 mix of generating output, and this is according to the EIA, 32% is gas and 33% is 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 for the mix of generation is 39% gas, 18% coal. They want to look at something closer to home, Ercot in the State of Texas through July 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 story. Wood Mack projects 8.6 BCF a day growth in electric generation load from 15 to 25.

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. When wind and solar combined generated less than 5% of total US generating load in 2014. And indicative of the lack of reliability, again 14 numbers, capacity utilization for wind was 34% and solar 28%.

That should not come as a surprise to anybody with any common sense, because we should realize that the sun doesn't shine all the time in the wind doesn't blow all the time, but some people have apparently neglected that understanding. What this really means is that reliable, flexible natural gas facilities are absolutely necessary to back up wind and solar. So to sum of 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 in the pipe being legal only in Colorado and Washington state.

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 is natural gas exports to Mexico. It is a real and 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 is an increase of 44%. This summer we found that natural gas exports have at times exceeded 3.0 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 GW of oil-fired capacity will switch to natural gas. Meanwhile as I think most of us know Mexico is gas production continues to decline.

Additionally LNG imports to Mexico are on the decline and they 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 3.0 BCF a day.

The third driver is the tremendous buildout 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 within 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 products.

Finally let's talk about LNG exports. They 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 US LNG export capacity will be 8.97 BCF a day only counting FERC-approved projects which have achieved final investment decision.

Those are the trends that are driving US 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 it nearly 2900 PCF of proven and potential reserves and that would be over 100 years of remaining resources relative to the current US natural gas demand.

In addition to being affordable and abundant, I want to stress again some facts about the environmental friendliness of natural gas. It emits about half the carbon dioxide emitted by coal and over 30% less than full oil according to the EIA. In fact natural gas has been essential to national and regional efforts to reduce carbon emissions. The White House Counsel of Economics reported earlier this year -- economic advisors reported earlier this year and I quote natural gas is playing a central role in the transition to a clean energy future, endquote. The report goes on to note that since 2007 energy-related CO2 emissions in the US 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 ISO 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 admissions of CO2 fell by 23%. Regional emissions of Knox fell by 66% and regional emissions of SOX fell by 91%.

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 one third of all the natural gas consumed this paint a very positive business picture for years to come.

With that I will turn it over to Steve.

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 and using common equity.

Because we are generating cash in increasing amounts in our business we have the effects ability to fund our investments in any number of ways, ranging from self fighting them with the cash that we generate all the way to disturb eating our cash to shareholders in accessing Capital Markets to fund our growth expenditures.

We believe our investors valued the latter, 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 challenge to equity market for the last two quarters, creating at least a perceived overhang in the market for our equity.

We believe it 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 deals. 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 equity investors. First, we are taking off whatever pressure that are common equity issuances were having on the stock. Second, we are continuing to fund our growth projects but at a lower long-term cost of equity capital then 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 in 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 50% 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 hit. Nevertheless, and while projections through 2020 are very assumption-driven, we believe we still could have grown the dividend. At the rate we have projected last year, however, coverage would've been tight over the period, and could of been negative part of the time.

Other companies have elected to run at negative coverage, but we believe be prudent decision for KMI and we believe the market is telling us this, is 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 is a question about finding the right combination of dividend growth and coverage in the appropriate alternative financing, and we think that in today's broader energy sector that is an enviable position to be in.

Now 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 SMT investments outside of the time frame of the backlog. So for the segments, in the third quarter reproduce $1.839 billion of segment earnings per the DD&A, which is essentially flat to 2014, and that is 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 impact in our GMP sector. We had a roll off a contract role of on Kinder Hawk in May, partially offset with additional volume commitment and the Eagleford by the same shipper.

We had the KML, Kinmore and Louisiana contract buyout that took place last year. We're having the effect of that this year on earnings before DD&A, and the rolloffs on the Cheyenne Plains system. Those last three items are 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 15% 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 in the gas group were up 7% as a result of the addition of the Highland Gathering assets. We continue to see strong demand the 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 2013 to 9.1 BCF of new and pending long-term commitments. Of that 9.1% it is worth noting 1.6 BCF of that comes from existing previously unsold capacity. So these sign ups are adding to our project opportunities, but also making better use of the existing capacity that we have.

Couple of project updates here. We've 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 made this product into the backlog pending some further progress on additional commitments.

But the prospects for adding this to the NED market path project, 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. 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 at FERC by 4 to 5 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 claw 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 on that.

First, the decline in the volume can be more than explained by a timing issue on Yates. Our next 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 transported 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 fully for the quarter, but up 6% year to date, and on track for a record year. Finally Goldsmith and Cats were both up year-over-year, but continued to be well below our plan.

We had been successful in extracting cost savings in this segment. We continue to forecast reduction in our OpEx and maintenance CapEx of just under 25% for the year. We've also seen cost savings in our expansion projects and as demonstrated by the adjustments to the backlog we are right sizing the 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 is up 29% year-over-year driven by the ramp up of volumes on KMCC, our crude and condensate lines serving the Eagle Ford. The addition of the HH pipeline from the Highland acquisitions. Improved performance on SMPP, as well as better year-over-year results on Kochan. 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 is 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 and 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 early in the quarter the Phillies tankers acquisition, which had 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 us a substantial force 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. The big news as always here is the transmountain 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 build.

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 year end 2018 and October of 2019.

Again there are a lot of moving parts here and we're going to be working hard on our detailed project execution plan to optimize all of that. But that's about the best guidance we can give you sitting here today on the inservice dates. A reminder also that this expansion is under long-term contracts, which have been approved by the NAB. We're very excited about this project. It is 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 will see that revenues are down significantly versus the corresponding period last year. But you will 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 hundred $198 million contract buyout on KMLA in the third quarter 2014 and the CO2 market to market, OpEx is down slightly more down than revenue, both in the quarter and year to date.

As I've 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, and 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 BCF 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 prior to our fusion transaction close, so a lot of the benefits 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%. You today we have generated $1.50 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.

There are a 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 a $387 million non-cash impairment on our Goldsmith deals, which is in our CO2 segment. That's primarily driven by lower crude prices.

The other certain items of any significance, the fair value amortization, and the mark-to-market, we see those in most quarters and we have discussed them in the past. The only exception is in the other category. It includes a $22 million write off of receivables assisted with the Alpha bankruptcy. The $22 million represents revenues reported in periods prior to 2015.

The $15 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 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. Let me put this in perspective. That reduction is just 6% of our total BCF and only about 5% of our EBITDA.

Now let's go 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 accrued, and a $3 million change in BCF for every $0.10 change in natural gas, the impact to our results is approximately $235 million. That is a little less than -- that is approximately a $70 million deterioration from what we expected at the time of the second quarter call due to deterioration's in commodity prices subsequent to that call.

As we talked about last quarter, our sensitivity assumed a constant NGL to crew ratio. That ratio has 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 have seen benefits and interest expense. We've seen CO2 and other cost savings. We've got downsize in coal and steel in our terminals business. We have lower oil production volumes in our CO2 segment.

We've got lower volumes from some of our product assets. And we've got lower capitalized 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 Highland 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. That's associated with lower coal and steel volumes, the largest piece being the $22 million impact of the Alfa bankruptcy and the FX associate 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 Highlands acquisition is slightly more than offset by about $20 million in 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 be below its budget by the year due to FX. And that's going to be, we think, about $20 million.

We expect to the 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 Highland employees and lower capitalized overhead as a result of lower expansion capital spending. On interest -- incremental interest is as it with the Highland 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 another way, we expect them to be a favorable variance versus our budget. 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. 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 a $50 million pension contribution. We had about $7 million in warrant repurchase. We issued equity of $1.27 billion. 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, so in our investment program. About [3.3] of that was acquisitions; about [2.65] was on expansion capital.

We made a penchant countries and of $50 million. We repurchased warrants of $12 million. We issued a little over $3.8 million 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'll turn it over to Rich.

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

Thank you, will we now begin the question-and-answer session.

(Operator Instructions)

Shneur Gershuni, UBS.

Just a couple of quick questions. I guess if we could start off with your - the 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 until the second half of next year.

I imagine (inaudible) 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 this something that the rating agencies typically score? Any incremental color would definitely be helpful to understand the financing plans for next year.

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 could talk about the backlog next. You've removed some projects from the CO2 bucket, but you 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 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.

It is 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 will 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 is in the backlog is already under construction, it jus hasn't -- we don't have revenue yet because it hasn't gone into service. The these are high probability projects that are secured by contracts where 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 will come back to, these are midstream assets where people are buying the space from us and securing it under contracts. And then we go get it approved and build it. If we think it is a high probability that it gets done it makes it into the backlog. That is 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 more programmatic spend. 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 is a little bit more programmatic and therefore, is more driven by commodity spend -- or commodity pricing. The other thing that's gone 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. So we have 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 has happened in CO2 is that we've had good results on the projects that we have proceeded with. 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 that we need. So, that is how the backlog shapes up. You have got to separate CO2 from the other midstream parts of the business, and those are contractually secured.

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?

There are a couple of ways to get at that. First of all, we have a very broad customer base. We have very few customers that account for even more than1%, say, of our revenue. We have got utilities. We have producers like BP and Shell are very large customers of ours. Utilities are large customers. The refiners, the integratives. All of them, and producers, and LNG. So we have got a very broad group.

On the -- the other way of looking at it is just 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 one- third each goes to LNG and producers and then the other one-third is made up of utilities and Mexico. So, that's how that breaks down.

Great. Thank you very much.

Brandon Blossman, Tudor, Pickering, Holt & Company.

Good afternoon, everyone. 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 see change -- the answer is probably pretty apparent, but what you need to see change in terms of common equity to be comfortable going back to that as a form of financing? It is just a yield problem, or is it a depth or liquidity problem for the common?

It is 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 is really more the cost of that equity capital to us. And what we believe we are 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.

There wasn't any 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 in, 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 it in that regard.

Thank you. That's actually very helpful. And then on the project side, 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 have a similar ruling in terms of allowing gas supply into the power generate base?

Massachusetts is really very positive, obviously. Beyond that -- Steve --?

I will start and then Tom can fill in, too. The EDC, what we call PowerServe, the offering that is specific to power generators or the power market, let's call it, pre-dated the Massachusetts order. But the Massachusetts order was very affirming in that regard, we believe. 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're think this is going to take time, because these things are processes. What Massachusetts is going to do, is they're 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?

I guess the only thing that I would add to that, Steve, is 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 -- stating that there's needed additional reliability for 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 that, that's showing consistent with some of the trend of the showing a need for incremental infrastructure into the region. So I think there have been some very positive developments here over the last quarter.

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 announce that it's 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 megawatts or 600 megawatts out and expect not to be able to use natural gas to fuel your needs for electric generation. The idea that somehow a swan is going to swoop down and deliver wind power or solar power in the next few months, or years even, to New England is just not facing reality. The only practical choice in our judgment, and it is 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.

Okay. So momentum moving in your favor, and I understand that there is not as 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?

We are still a little bit early in getting some of the LDC piece of that. So it is really 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.

We'll know a lot here more over the next three or four months.

Okay. Thank you very, much guys.

Darren Horowitz, Raymond James.

Steve, a couple of quick questions. The first to the extent that you can answer it, with regard to lowering your long-term cost to capital, can you just give us, even if it is 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 burdened by multi-year dividend growth ahead? I'm just curious, when you did the analysis on that cost savings, was it more built on the extrapolation of 6% to 10% annual growth of 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.

If I can just shift gears back to Rich, in your prepared commentary about being financially flexible for the opportunity of third-party assets, how do you think the Northeast infrastructure supply demand dynamic changes not just via the pending large-scale mission consolidation 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 downstream logistical opportunities. Maybe some with increase residual value that give you the opportunity to leverage your refined products business or terminal footprint? Any commentary there would be helpful.

I think are a 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 a first priority. But as we've said all along, we've reversed size proportions of the Tennessee system to get it back down to this area to serve the LNG load, the petrochemical load that I refer 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 of these opportunities over the last couple of years. Tom, anything else on that?

No.

Thanks, Rich.

Mark Reichman, Simmons & Company.

Just a quick question on the rating agencies. I think of the last call you mentioned that they were willing to live with the elevated credit metrics until Elba and Trans Mountain were starting to contribute, which would show some improvement in the credit metrics. And I was just wondering, now that it looks like both of those projects are experiencing 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 looking for, and timeframes for living with an elevated credit metric?

This is recent news on Trans Mountain and Elba, but if the projects get pushed out, so does the spend. So what is driving the leverage to stay high over time is the fact that you are spending dollars with no cash flow coming in. And so I believe we'll be able to manage through that.

And so that 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 project and the project delays being linked to our decision to go to the range or to look at coverage. No.

Let me just say again, just to be very clear on the range. As Steve and Kim both have both indicated, we are 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 have 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 is 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 is very helpful.

Kristina Kazarian, Deutsche Bank.

Hello, guys, I appreciate -- Could you guys to 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 2017, 2018, and 2019, if there is anything there?

The 6% to 10% is just the uncertainty that we have before we go into the budget process and wanting to make sure that we are going to be able to fulfill that and also aim for an appropriate amount of coverage. And in terms 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 to's and fro's within our underlying assumptions. If you go back to where we were when we announced a consolidation transaction and just try to examine, okay, what has changed over that year. Certainly the one thing that is a negative that we talked about at length has been the change in commodity prices -- the direct and indirect impact of that. On the plus side, we had a much improved tax depreciation benefit and a tax depreciation number from what we had when we originally rolled out the assumptions around the consolidation transaction. Such that we now 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 that were moving at the time, we also -- I think we projected some capital spend, I think we have been basically on track on the amount of capital that we've deployed, although we do have some pluses and minuses associated with project delays. We have some minuses associated with project delays. We've been able to find plenty of opportunities to invest in the capital.

And then, I'm trying to think, there's one other factor in there that was built into -- we did not include anything for acquisitions. We I think had a couple hundred million dollars, we had some small tuck-in acquisitions at the time. And if we did any significant -- one or two significant acquisitions over the time period, that would be a potential upside to those numbers.

I was going to say when I think about it historically, you guys normally give me the budget update I think in December. Do I think about from a long-term perspective, maybe I get an update in December, or do I get with the next analyst day? How roughly should I be thinking about this?

Generally, we have updated our guidance in January. But I think to go back to what Steve said at the beginning, which is when we did fusion, we believe we can grow at 10% per year and we have substantial excess coverage. And what we're saying today is that the deterioration in the energy markets has essentially taken away a lot of that excess coverage, so some of our flexibility.

So we could still choose to grow at the 10%, but coverage might be -- could be, we don't know -- projections are very assumption-driven. 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 just last thing, when I'm thinking about your target leverage level for year-end, I know we've talked [particularly] about the 5.6 times. How do I think about that number for 2016, 2017, what is 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 Trans Mountain and some of the other projects on and then we would expect that to decline to the low 5s.

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

Ted Durbin, Goldman Sachs.

I hate to beat this dead horse, but the coverage issue is really what I'm focused here, and it just feels like moving 8% at 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'm just trying to get a sense of where your head is on coverage.

Again, I think what we're -- and we think the market is telling us this, where things are valued right now and at our current equity yield, it doesn't appear that people are really valuing the growth and dividend so much as they are some stability around that. 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. So we're going to be striking that the balance as we go, but that's, I think, the message that 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 it is more important to have some more flexibility than to have coverage, then we can do that. I think -- and let me just say, we have been saying for a number of months now that the coverage has been substantially diminished versus at the time we did fusion because of the dramatic change in commodity market.

So what we are saying today is no different with respect to what is 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 then again thinking through then the backlog and how you are thinking about the hurdle rates on projects, I guess what you're saying is you're not happy with where the valuation is in the equity. Have you 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. When it comes to the cost of the capital -- so all of the stuff that's in our backlog is it accretive, it is beneficial to our investors, even with today's elevated yield and elevated cost of capital. It obviously cuts into it a little bit the longer it lasts, but they are still very attractive investments even at our current cost of capital.

And we will continue to be very judicious. We are constantly reviewing among us in the business unit presidents what our cost of capital is on a long-term basis, what is on a 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, that you said you don't think you're now going to be a cash taxpayer until 2020. I thought the number was more like 2017 or 2018. Is there anything that's changed there (inaudible)?

We now anticipate we will not be a significant federal cash tax payer until 2020. And then as Steve was saying, life in general is a mixed bag of things. Positives and negatives and with return -- in terms of the project 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 will leave it at that. Thanks.

[Jeremy Smith], JPMorgan.

Thanks for the color today. Was just curious about 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 is 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?

I think the only thing are the general things that we already said, which is what we are fundamentally going to manage to. One is accessing the capital markets in what we think is on a long-term lowest cost of capital available today basis. And second is maintaining investment grade rating, and third, of course, it should of been first, is maximizing value to our shareholders. So that is 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, I know it's really early in the process, and I know obviously commodity prices will be a big part of it, but I'm just wondering, when you're thinking about 2016 guidance talk about some uncertainty there that could drive dividend growth within that range of 6% to 10%, what are the other factors that you see that are big variables that could push the results towards one or the other?

The reason, again, for the range is just the we haven't gotten the specificity yet that we need to really be able to answer that question. That things that drive our business typically when we get into the budget process, there's a big focus that we placed on costs. That focus will be there, again, this year, just as it always is, we want to operate safely but efficiently. The impacts -- the year-over-year impacts of 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 will be taking into account.

Really, we think that for a business of our size it is remarkable that we can call our shots really as well as we can. That is 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 Vice President of Corporate Development, talk a little bit more about the M&A market.

Just to give a little flavor on the market, and I break the market into three buckets based on value. With respect to asset deals and what I call low- to mid-9 figures, or call a few hundred million dollars, I think we're starting to see some opportunities. We obviously just announced the BP deal, and I think we are going to find some more deals over the next 6 to 12 months that are similar in size.

There is always 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 deals, but are nice investments nevertheless. You move up a little bit to potential asset deals, single asset deals, that are in the, call it, $1 billion-plus range. We continue to evaluate deals in that range and have looked at quite a few recently, but we've really just haven't to gotten there on valuation. I think the bid/offer spread issue that is so often discussed is persistent there.

We've taken into account some of those expectations on price and just the risks inherent. We simply haven't seen situations where we're willing 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.

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

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

So far still a North American focus. We 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, ad nauseum, the fact that we're no longer an MLP means that it gives us more ability, or flexibility, to do projects outside of North America. But again, they would have to be very high return projects for us.

Very helpful. Thank you.

Faisel Khan, Citigroup.

Dax, just going back to your comments around M&A, I appreciate you splitting it up into the 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 that you've seen a lot of carnage in the MLP midstream space? I'm just trying to understand what your view is on the value -- the corporate that is in the market today?

So by the third bucket, I assume you mean the larger one, as we always say, you have to have three things. First, you've got to want the assets and then you have to convert the three things. First, you've got to want the assets and then you got to have the valuation and then you got to have social issues. You got have to have the perfect convergence 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 -- having the three of those converge is extremely difficult and extremely difficult to predict when that is going to happen.

Okay. And in terms of financing your growth, if you look out in the debt markets today, what is your preferred mode in terms of financing your capital spendings? It is through fixed floating -- and how your debt issuance costs looks today versus where they were six months ago?

We're going to fund in order to retain investment grade. 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% floating. We're about 25% floating overall right now, that's just because we did El Paso, the acquisition came with a lot of fixed debt. But on an ongoing basis, typically we're swapping about 50% of our debt (multiple speakers).

Got you. And on the cost -- as your debt issuance costs remain roughly the same over the last six months, we've seen some issuers see their spreads blow out a little bit, even though they're investment grade.

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. What is the procurement plan for that backlog of for steel and pipe and other sort of materials? We've seen the stronger dollar and we seen steel costs come down. So what is a plan to try to reduce the cost of that backlog and increase the returns, or is there a plan?

There is always the plan to get everything -- 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 when we have to. So we do that on a project by project basis. And Faisel, it is really a mix of things across the spectrum. Sometimes we will get steel trackers that are negotiated because that is a variable commodity and on a (inaudible) project you are not sure what it is going to be when you get there. We have gone from having steel trackers. We have done some preorders. We've done a variety of things, and it is really pretty situation specific. But we're very focused on finding 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. If anything, I think we're putting even more focus on that than we have historically. It is just we're watching all those things very closely.

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

Okay. Got to and then just on the backlog -- does that incorporate where steel costs are today are were they were 6 to 9 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 what our procurement group is showing us as the price per horsepower, the price for 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? The same thing with equipment providers, materials providers and the rest of it and is it a mix. Things are still pretty active in Houston and we're 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. We're just -- I don't know how better to answer it than to say we're very much on top of it.

That is fair. I appreciate the time. Thanks, guys.

Craig Shere, Tuohy Brothers.

I appreciate the call and keeping it going a little bit 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've got to pick some point in time and this could -- we can really defer 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. The rest of this year and the middle of next year. And beyond that, we will take a look at what we want to 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 the issuing common equity. Our views have taken that off the table longer-term and most importantly achieve, on the long-term basis, a cheaper cost of equity financing.

Okay. We'll let it go at that.

I'm sorry we cannot share more with you, but my General Counsel is sitting across the table for me. We just can't say any more under applicable rules without -- we don't want to be front running anything. As Steve said, you will know soon enough and we will 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 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. So we continue to make progress on it and continue to pursue it and believe we will get it done.

Okay. That's helpful. It's understandable that the EOR investment is coming down and some of the CO2. My question with SACROC I think the lowest level now since third quarter 2014, we had a little drop this quarter, if this goes on for, what have you, another three to six quarters and then energy prices come back a bit and makes 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 and not an economic issue. We will continue with the current prices to develop the field. We maybe have a temporary lull in production based on an area in the field, but we are moving throughout the field to improve production. We are not pulling back on existing CO2, or EOR, in SACROC or Yates or any of the (inaudible) at this point (inaudible) current market.

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

It can always be recovered.

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

That is correct.

It is a positive story in our view. Not a negative story at all. But where we have cut back, and Steve has made this point in spades, I think, is where we have cut back is we were getting ready to ramp up 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 is mostly where the capital reductions in the CO2 segment have come from.

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 alluded to as potentially being big long-term at the 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 stimulation that you were hoping for? If we had $60 oil prices again, could this be as big as was discussed previously?

Jesse?

We still maintain a positive outlook. The volume metrics, all the early indications are positive. The processing rate is a little slower, but we're implementing a plan to speed that up. Phase 2 at this point seems economic, or is economic. Going forward into phase 3 and 4 and as you start putting in more facilities in the processing will claim that. We still believe that that is a viable project long term.

Okay. Thank you.

Becca Followill, US Capital Advisors.

On Trans Mountain, can you talk a little bit about whether or not, with the pushouts, 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 an out in their contract?

We have Ian Anderson, the President of Kinder Morgan Canada, and he was waiting for the question.

Sure. Thanks. You made my trip down worthwhile.

I am so happy.

Let me answer it this way. As far as the costs go we have been reporting $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 billion project; so if you convert the $5.4 billion American, that is about CAD6.8 billion today. And a few things have driven that, both some scope changes to the project, foreign exchange on non-Canadian source bits of materials, as well as the impact of the delay. If you add those three factors together, the project is currently sitting on about a CAD6.8 billion forecast, or about $5.4 billion that we have been reporting.

Thank you. I think, Becca, it is fair to add that both from the standpoint of cost parameters and timing parameters, we are well within the bounds of our contracts with our customers.

That is right. Contracts with our customers contemplate CAD6.8 billion capital to the project, under which they've got no ability to de-contract their commitments. 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 is very helpful, Ian. Thank you. And just to clarify, so if it does go over the CAD6.8 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 CAD6.8 billion, that gives them the out.

Okay. Thank you.

That is an important distinction.

Okay. Thank you. And then on your Northeast pipelines, not so much the Northeast Direct, but some of the other pipelines that are more producer driven, there are -- some of the producers now have a lot of excess ST. Any pushback by 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 the commitments they've made the date we're standing behind and we're not seeing any issues in that regard.

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

Not to this point. No.

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

It is already FID.

It is FID. So as soon as you get the final FERC approval, it is good to go?

We start shoveling dirt. Yes.

Perfect. Thank you, guys.

Noah Lerner, Hartz Capital.

Good afternoon, or maybe you should I should say good evening, everyone. A quick question. A little bit out in left field, though. I'm just curious on Trans Mountain, any other ideas you have brewing up there in Canada, what with this week's election, how that might impact your thinking or your operations up there, knowing that you have a 100% controlled government now by the liberal party up there?

Let Ian answer that.

I am wearing my liberal red tie. It is too let early to speculate on what a liberal government is going to mean for us. We're going to continue to focus on the NED process that we are involved in and all of the requirements of that while we continue our project planning and preparation. We'll 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'll 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.

John Edwards, Credit Suisse.

Just if I could, on the dividend growth outlook, I know in the past you have indicated 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 6 -- it had been like a 10 and it came down. And with the revised growth range, how should we be thinking about what kind of fill-in capital projects would be needed to meet the new objective?

I think you should think we're got the capital objectives and we'd always had John. And as Steve said earlier, we are on track to do that, with our backlog and what we've already brought in service, if you 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 fusing 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. So then longer term, should we be thinking about a range? 6 to 10 longer-term range or paralleling 2016? Is that correct?

Okay. I'm going to try.

Sorry Kim, I know you have gone over it a bunch of times. Just to be clear.

I'm going to try one more time. So 2016, we have not 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 that people are going to want an update today. Over the longer term, what we think, what I said earlier is that when we did fusion we thought we could grow at 10% for a year. We had a substantial excess coverage. What this energy market has done is it has essentially depleted that excess coverage.

So now we think that we probably can grow at 10% longer term but that the coverage would be very tight and could be negative in some years. So what we are saying is that as we go forward, we're 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 is saying the capital assumptions have not changed, the underlying assumptions in terms of the capital spend have not changed. Now, some of the volumes have deteriorated, the oil price has deteriorated, and that is what has driven the depletion in coverage.

Okay. That is very helpful. And then just lastly, I hate to keep coming back to this, but just in terms of modeling the alternative financing. 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 lastly on Trans Mountain. Just to follow up Becca's question. There's only a cost out, 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 is all I had. Thank you.

Corey Goldman, Jefferies.

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 going to the appeal process and take it from there?

It's true that it's not a requirement that we have public -- a certificate of public convenience of necessity from the Georgia DOT, but our appeal is about continuing 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 at 45% at $75 a barrel, and 2019 is 24% at $66 a barrel.

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

Yes. I think it is probably -- it is very close, but probably just slightly under what we had anticipated for this current year. When we put our projections together for Hiland, we gave them -- we gave the sellers productions a pretty good haircut and we didn't assume oil price recovery really at this year or next. We gave ourselves some pretty good running room there. I think probably a little bit under on the revenue side, a little better on the cost side. That includes just operating cost, 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 in queue, I would now like to --

Thank you, everybody, for bearing with us for 1.5 hours of informative questions. And it 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.