Thank you for standing by, and welcome to the quarterly earnings conference call. (Operator Instructions) This conference is being recorded. If you have any objections, please disconnect at this time. I would now like to turn the meeting over to Mr. Rich Kinder, Chairman and CEO of Kinder Morgan. Go ahead, you may begin.

Thank you, Sharon and welcome to our first quarter analyst call. As usual, we’ll be making statements within the meaning of the Securities Act of 1933 and the Securities and Exchange Act of 1934. I'll give an overview of the quarter, then Steve Kean, our Chief Operating Officer, will talk about the performance of our five business segments and give you an update on our backlog of expansion projects. And then our CFO, Kim Dang, will explain the financial results in detail, and then we'll take any questions that you might have. Our Board today voted to increase the dividend for the first quarter to $0.48 or $1.92 annualized. That’s up 14% from the first quarter of 2014 when we paid a dividend of $0.42 per share. And it’s a 7% increase from the $0.45 we paid for the fourth quarter of 2014. This is consistent with our announced intention of declaring $2 per share in dividends for ‘15, the full year of 2015, which would be a 15% increase over full-year 2014. And we are on track to do just that. We also continue to project growth in that dividend of 10% per year off of that $2 base out through 2020. Our DCF per share was $0.58 for the first quarter, which equates to coverage in excess of our dividend of $206 million. Now, any comparison with the first quarter of ‘14 is a little bit apples to oranges, because of course we didn’t roll up KMP, KMR and EPB until the fourth quarter of 2014. That said, I think the simplest comparison is this. In the first quarter of ‘14, we had 1.036 billion shares outstanding. We had DCF of $0.55 per share. We declared a dividend of $0.42 per share, which resulted in excess coverage of…

Thanks, Rich. I’ll give you an update on the project backlog. Also update you on two projects that are not in the backlog, and give you some operational commercial highlights from the segments. Since our January update, on a comparable basis, the backlog decreased a little bit by about $200 million. The main changes were that we added 1.1 billion in new investments to the backlog, about 40% of that is the addition of the high probability portion of the Hiland backlog. And the balance is made up primarily of additional gas pipeline and terminals expansions. We put into service almost $400 million worth of projects during the quarter, with half of that represented by the startup of the first condensate splitter of our two splitter project in Houston ship channel. But just taking into account what we added and what went into service, we grew the backlog by $700 million even while putting into service $400 million worth of projects. The big offset to what would have been a net addition to the backlog is the removal of about $900 million, the vast majority of which came from our CO2 business. And so what’s going on there is while CO2 source development is economic along our existing infrastructure, meaning Southwest Colorado and the Cortez pipeline, new developments -- and we're going to continue to expand our capability there. It's harder to make new CO2 developments work in the current commodity price environment. So we pushed St. John's field and the Lobos pipeline developments outside the time frame of the backlog. In this price environment, that's simply the wise thing to do. New CO2 source developments aside, I think the takeaway here is that we continue to see strong demand for expansion of our midstream pipeline and terminals businesses, notwithstanding…

Thanks, Steve. Let me start first with the GAAP income statement and one comment on it before I move to distributable cash flow. If you look on the GAAP income statement, you can see that revenues are down about 11% or 450 million. But if you also look at OpEx, it's down by 531 million or 25%. And the largest contributor to this move in revenue and OpEx is our Texas intrastate business where we buy and sell natural gas. Now we largely match up our purchases and sales. For example, if we enter into a contract to buy at Houston ship channel minus we also enter into a contract to sell that Houston Ship Channel flat; with the result being a fixed margin of 10%, but your revenues and expenses are going to fluctuate with commodity prices. We also have somewhat similar characteristics in some of our other assets in our portfolio, and that's what's contributing to this large change in the revenue and OpEx. Now changes in revenues, we don't think are good predictor of our performance. We continue to believe that the best predictor of our performance is change in distributable cash flow per share, and the change in the dividends per share. But given the large change during the quarter, we thought that was important to explain. So moving to the second page of our -- of numbers in our press release, which is KMI's calculation of distributable cash flow which we reconcile to GAAP net income. We use distributable cash flow as a measure of the cash we have available to pay dividends. The same format that we used in the fourth quarter of last year for KMI and DCF is calculated as net income excluding certain items plus DD&A, plus book taxes, minus cash…

Okay. Thank you, Kim. Thank you, Steve. And with that, Sharon, if you’ll come back on, we’ll take any questions.

Thank you. (Operator Instructions) Our first question comes from Shneur Gershuni of UBS. Go ahead sir. Your line is open.

I just wanted to start off at a high level. There's been a lot of attention about M&A. The recent Royal Dutch deal and so forth. And given your interest in M&A as you've explained at the Analyst Day and so forth, I was wondering if you can give us some color as to what you're seeing out there? Are there distressed assets available or non-strategic assets coming up for sale? Have bid asks narrowed a little bit? Can we expect Kinder Morgan to be active in the coming months, or as things moved with the price of oil and so forth?

I think you can expect us to be active in the coming months. Answering the last part of your question first. Obviously, we've made two acquisitions already, the 3 billion, 3.1 billion Hiland and then the Vopak Terminal acquisition, which was a little over $160 million. So we've not been sitting on the sidelines. That said, we continue to look for things. But obviously, they have to be a fit both in terms of accretion to our shareholders, to our distributable cash flow and doability. And there's a lot of cheap money out there chasing deals right now. And that's pretty common knowledge how much money has been injected into the energy patch just in the last few weeks. But I'd like to get Dax Sanders, our Corporate Development Vice President, to maybe expand on it a little bit. Dax?

As you said, we've spent a lot of time looking at various potential opportunities. But as you well know, with acquisitions you've got to have three things. You've got to number one, want the assets, number two, you've got to have valuation work, and number three, you've got to get past the social issues. And I think there are certainly things out there; I think that bid offer spreads certainly do continue to persist. And notwithstanding that, there are certain things that are transacting. Obviously, we were able to get Hiland done. I think we certainly have, as Rich said, an appetite for more acquisitions. And I think we've got a good track record of executing on acquisitions, and successfully integrating them. And I think we've got plenty of capacity and ability to execute and integrate other additional acquisitions and we continue to spend a lot of time on it.

A couple of quick follow-ups. We've spent a lot of time in the energy world talking about the price of oil over the last couple months. But natural gas prices have been down quite a bit as well too. When I look at the changes that you announced for your backlog, the only change so far is really -- negatively speaking has been in the CO2 business and you've been successful in adding projects as well also. I was wondering if you can talk to how the natural gas price may impact your backlog and/or the shadow backlog on a go forward basis. Could we see potential negative revisions, or are you immune to it?

I'll start, and then I'll ask either Steve or Tom Martin to comment on that. But the overriding principle here is that we are seeing a dramatic increase in natural gas usage. Long term, we expect it to go from the 74 BCF, 75 BCF a day today to 110 BCF in the next 10 years. That's being driven by demand pull and supply push, but a tremendous opportunity for the largest midstream player like us. And we're just seeing indications of that. Steve mentioned what increase in our capacity sign-ups that we've had again just in this quarter. But I think the main thing here is, that this demand will continue to drive more growth and we're certainly seeing those opportunities.

The demand side is where it's happening. The big example would be Northeast Direct if we get that done. Now there's a supply -- the supply [indiscernible] that is a combination of demand pull and supply push. But we're going to see demand pull if Northeast Direct gets under contract coming from LDCs and power plants. And that's the biggest chunk. Now what Tom's team added in this last quarter was also power plant -- expansions for power plants, signing up some capacity with utilities that was previously unsold. So you definitely see the demand pull starting to show up. From a backlog standpoint purely, again, NED is the big deal. Northeast Direct is the big deal. If you break down the rest of the market and say, well, there's going to be additional gas demand to the extent that it comes through a gas utility, then I think you'll see contracts get underwritten for expansions to -- and we announced one on NGPL here just yesterday, expansions will get underwritten. When you're talking about power plants, it's a little bit more of a mix. Some power plants in a vertically integrated utility, they can commit to long-term contracts. When you look at industrial and petchem, those guys typically are not signing up for long-term contracts. They expect to connect and then be able to buy their gas. But even in that case, as Rich said, that's pulling demand up on the system. And that makes the underlying system more valuable, and it drives expansions even in a more of a market pull environment. The other thing, and we've emphasized this in the past is that -- is storage. A lot of people think about and we think about transport, but we've signed up about 3 BCF in storage so far for LNG customers. We think they're going to need sign up for more. That 3 BCF came out of existing inventory. And when you think about our power plant demand and LNG demand that implies a certain amount of storage that's going to be needed in order to manage the fluctuations in that demand. So I think the market pull, part of this will again continue to enhance the value of the network.

I guess the last part I think to the question you were asking is the range of the shadow backlog. And I think we talked about something in the $17.5 billion range just in the gas group alone at the analyst conference, and I think that number is still pretty good as to where we see opportunities at this point in time. And a big chunk of that is NED, which I think we're getting ever closer to moving forward on.

Great. And one final question, Kim, you had mentioned the reconciliation on the equity that was issued under the ATM and so forth. As well as the goal to get to about 5.6 times levered by the end of the year. Can we expect a similar pace of equity issuance throughout the year? Or does the seasonality of your earnings given the second quarter is not often as good as the first quarter, does that change the pace with which you intend to issue the equity and so forth? I was wondering if you could give us some color on how it will flow throughout the year.

The seasonality does not impact when we choose to issue the equity. The price may impact when we choose to issue the equity and there may be some other things that impact that, but the seasonality is not a factor that we consider.

The next question comes from Mark Reichman at Simmons. Go ahead. Your line is open.

I just wanted to ask a little bit about the Hiland transaction now that you've been working with it for a couple of months and the Double H is into service. What are you seeing in terms of activity in the area? Your expectations for volumes? If you could talk a little bit about Double H, and I know the capacity is 84,000 barrels per day, where that's running and expectations for the rest of the year. And then also just lastly, I think the plans were to spend about $850 million on that asset portfolio. If you could just talk a little bit about your plans there and just really just an update on the deal.

So overall, just a reminder, we closed the deal on February 13th. The integration is mostly complete and going pretty well. Certainly considering the speeds between sign and closing which was pretty tight. The overall -- based on what we've seen thus far since closing up till now and what we're seeing for the remainder of 2015, taking into account feedback from the producers and our customers. The acquisition is performing, and taking in everything into account in line with our expectations, maybe a tiny bit better. We did have some issues on Double H with the start up. We were delayed several weeks past our anticipated start up, but we believe we're mostly past those and Double H has ramped up and is running nicely. I think one thing on Double H that we mentioned during the time of the deal is that we were running an open season. At the time of the deal, we announced that we had firm contracts for 63,000 barrels a day, or right around 60,000 barrels a day. That open season produced an additional 17,000 barrels per day. So we do have contracts now for 80,000 barrels a day of the 84,000. So Double H has ramped up, and is running very nicely. But again, I think I would summarize and just say it's running consistent what our acquisition economics were, maybe even a little better.

So were the volumes -- what were the actual volumes then? Were they at the 80,000 or?

The start-up actually -- we were anticipating that the start-up was going to be right around the beginning of February, the start-up actually finished right around February 27th. Right around the end of February, after that, we started ramping up slowly. So we didn’t -- we certainly didn't ramp right up to the 80,000 barrels a day -- some economics, certainly took into account. We never assumed that we were going to get right up to the 84,000 barrels a day. But we've ramped up over time; we're still working on adding the DRA so the volumes have really been all over the place.

So what are they now? And then what would you expect them to be once you add the connection to bring the short-haul volumes the system?

We expect to have capacity to move the 84,000 barrels a day and we expect the volumes to be very close to that.

And our next question comes from Brandon Blossman, of Tudor, Pickering, Holt and Company. Go ahead. Your line is open.

Let's see, a specific question and then maybe something broader. On NED, is there a structure or is there some regulatory work to be done as far as cost sharing between the LDCs and the merchant generators in that market? And as a follow-up to that, is that something that maybe the outcome is it possible that that is unique and could be used as a template for other markets on a go forward basis?

There is a regulatory process underway in New England to really give all the power customers the platform in which they can equally share the cost of transportation capacity and I think that's what's being developed right now. It may involve utility customers potentially carrying some of this for a period of time, and then transitioning to the power customers directly. Yes, I know, I think it's probably going to manifest itself in a different form than what we've seen in other parts of the country. But in the Southeast, for example, it's probably the same concept where all the power customers are on the same playing field, and the capacity -- the cost of owning capacity is equally valued in the marketplace. And so therefore, the incentive there is to go out and contract for long-term capacity. We think something like that will ultimately be what occurs in New England.

It's certainly interesting to watch, and there's a lot to play for there as far as generating capacity?

The economics are very compelling, so I think we'll figure it out.

Certainly, right now in spades, Secondarily, bit picture, and this is another way into the M&A question ultimately, but obviously rate count is down, the folks are getting more comfortable with at least to the thought that we're going to hit the pause button on gas liquids and oil production growth over the next call it 12 months or so, does that change in any way how you approach strategically thinking about or ranking M&A either bolt-ons or larger acquisitions over that time period? Or is this just a bump in the road and you guys are looking past that?

Well I wouldn't call it a bump in the road, but certainly we take a long-term view when we enter into discussions on any kind of acquisition. And certainly, we think, there are still opportunities out there and we're going to look at them. You've got to be opportunistic, as Dax laid out some of the criteria earlier. But we don't think this is a retardant to the potential of acquisitions. The real retarding factor to acquisitions right now is that there's just a lot of very cheap money flowing into the energy segment, particularly in the upstream area, that are backing companies that otherwise might be more in need of selling midstream assets that we would be interested in, if they didn't have some of this capital flowing into their operations.

Our next question comes from Darren Horowitz of Raymond James. Go ahead sir. Your line is open.

Two quick questions for me; the first, Steve, back to your comments on UMTP, I'm just curious what the revised offering to accommodate like you mentioned a batch system versus just an outright y-grade system. How are you guys thinking about the variance between maybe the targeted tariffs or expected returns on batch movements relative to contract durations? I'm just trying to get a sense of -- now with the lower cost to capital, what kind of volume and margin blend do you need from a binding commitment perspective to get this into backlog? And more importantly, has anything changed? I think initial proposed scale was like 375,000 barrels a day.

Yes, I think first of all, I don't think we've got a -- it all depends on how the contracts shake out. How much people are willing to pay, how much the market will bear. That, in turn, tells us how much of the volume that we need to get signed up. Look, the producers up there are struggling with this changing commodity price environment. I think the advantage of switching over to this model and what is attracting some interest is we're maybe not competing with local fractionation any longer. We have the ability to take purity products, and batch purity products through the pipeline, and that’s I think a superior offer. Just having options generally and the ability to switch around on what you're deliveries are going to be is going to be more valuable to producers than saying, hey, you've got to just put y-grade in here, and you've got to commit to downstream fracks, and then you've got to commit to something after that. So again, we think it's a more attractive offering. We're battling people stepping back a little bit with lower commodity price environment. But we're getting interest with this, and we'll keep pushing at it. We haven't looked to lower our return thresholds on this project, notwithstanding the post-consolidation world. We're going to look, as we do in all cases, to get what we think the full-market value is or fully priced value for our services. So I wouldn't say that our return criteria have changed, and again, I think what price and what volume it takes to get this project on the backlog is really still to be determined.

Okay. And then last question for me, not to beat this thing to death. But I'm curious around NED. And you guys outlined some of this in the release, but if you look at the current discussions with the electric distribution companies, the potential for more power plants, et cetera, and others that you're in discussions with. From an aggregated capacity commitment perspective, what do need to get in addition to the 550 that you've locked down to move this officially to backlog?

I don't know that I can give you specific number. All I can really say is that we're moving very close -- we're getting a lot closer. And I think we'll have a lot more clarity as we get through the end of the summer.

Our next question comes from Ted Durbin of Goldman Sachs. Go ahead sir. Your line is open.

I’m going to stick with NED and ask it in a different way here. Have you thought about splitting the project at all to where you would move forward with the supply portion ahead of doing the demand side, or does it still feel like it needs to be an integrated project?

It's really not an integrated project right now. We’re looking at them both separately. And if we get adequate commitment levels on the supply product to move forward, we’ll do that. And that’s developing well as well. I think the timeline is similar. We may have more clarity on the supply project sooner than the market, but I think both are looking more clear as we [technical difficulty] summer.

And how is your capital cost breaking down between the two, is it 50-50ish, or?

It’s about two-thirds market and one-third supply.

And then if we can come back to the CO2 transportation side of things. I guess I’m wondering we took a lot of the backlog this quarter. What is it? Is it a certain oil price or a certain volume ramp up that you need in say the Permian in which these projects come back into the money? I’m just trying to the sense of where the market needs to go for you to say, these will come back into backlog in your customer’s [minds].

I’ll start, and let Jesse Arenivas finish or clarify the answer. But I think this is a function of CO2 demand, which in turn is function of the use of CO2 either in grading quantities or existing floods or in new floods being added. And so what you have to ask I think is what’s economic in terms of CO2 flooding on the EOR side. And clearly, existing CO2 floods and maybe even a little incremental demand possibly in an existing flood, that’s economic. But people are going to be hesitant in the current commodity price environment to make the up-front capital commitment that would be required to add new CO2 floods. And that’s really what would drive a lot of additional demand. We believe that the demand that we can see for the next few years at least is demand that we can serve with our existing Southwest Colorado production and Cortez pipeline, plus an expansion of really of each of those that are underway, and we think that will take care of it. So that’s a long way of saying, I think what is required is incremental demand for CO2 probably represented by new CO2 floods. Which probably need a commodity price change to make it happen?

Yes, I think its right, Steve. I think you’ve covered it. You’re probably looking at -- to answer your question on would include price and new economic decisions are probably [viewed] by $80 to $85 WTI.

That’s very helpful. Thank you. And this last one, you talked about the 20% decrease on the CO2 side. Is there anything that you’re seeing outside of that on potential cost savings, whether it’s operating or capital cost savings, just even the deflationary environment we’re in?

You mean outside of the CO2 segment?

Yes

I think we’re seeing some things. But so much of our activity -- a lot of the projects are on the Houston ship channel area, the Gulf Coast where there is a tremendous demand for infrastructure all the way from LNG facilities, to petrochemical plants, to additional terminaling activities along the ship channel. And then big investments, both in our rail terminal with Imperial and this new major merchant terminal up in Edmonton, which is becoming a real hub up there, given the volatility of oil prices, et cetera. Those are two areas where the demand for the kind of services we need are still pretty high. So I think you would not expect to see a lot of improvement there. Some other areas we are, and then particularly, as you recall, we targeted 15% savings in our CO2 segment. Jesse and his team are now on that targeting something 20% or a hair better. So we’re making real progress there, but I don’t think we’ve seen major changes outside of that upstream CO2 area.

Fuel costs. Fuel costs are improved, and that’s the main thing.

We may still see it, but we haven’t -- it hasn’t come through in a big way yet because there again continues to still be a fair amount of demand for the pipeline investments that we’re involved in and competing for.

Okay, great. Very helpful. Thanks. I’ll leave it at that.

And our next question comes from Carl Kirst at BMO Capital Markets. Go ahead sir. Your line is open.

If I could just go back to NED for one second just to make sure I’m understanding. Is the main process still live and is that outside of essentially the broader regulatory process that’s going on in New England?

Yes, I think they’ve got a path that’s closer to closure I think than the rest of the New England regulatory process. So I think it’s likely that we’ll see a decision there late summer or maybe early fall. And I think the rest of the process will probably be more in the fall.

Because I think we had originally thought maybe that might be happening maybe at the end of last year, I think even it might be this springtime. And is that just a matter of these things just take longer because of red tape involved, or has there been an issue that has come up to be aware of?

I wouldn't say it's an issue, I think it's taken longer. They're continuing to study what their need is, and the process they want to be somewhat coordinated with the rest of the states and don't want to get too far out of front. So I think that has what's led more towards a latter summer time frame for them.

Okay, that's helpful. Thank you. And the maybe, second question if I could, and, Steve you said this is on Trans Mountain. And trying to think about the First Nations for a second and I guess we're around seven to eight bands right out of the 24 core. And is it still your expectation or perhaps belief that we can get to a majority of the First Nations on-side, or is that still being viewed as almost a prereq to get NEB approval or can you get that approval, do you think if you don't get any more bands to sign on?

A couple things, Carl. One is that; yeah, I think we still expect that we're going to get a majority. But just as important, the standard that we are held to, and really it's a standard that the federal officials -- the federal government is held to that we discharge for them by engaging in it, is consultation and reasonable accommodation. And we will absolutely do that, even if we can't get someone to sign an agreement saying they support the project. In other words, we will -- we've engaged everybody. Frankly, there are handful of bands, coastal bands, some of which who have refused to engage, but it's not something that we have failed to do. We've engaged with everybody, consulted with them. We will accommodate and consult; we will meet our statutory standard. What would like though is to get further than that and actually get mutual benefit agreements which require support of the project signed with a majority of the core, and we still think we'll do that. But so you have to think in terms of what is the real obligation that we have, and are we going to fulfill that, and the answer to that is yes. And then he further is how much better can we do? Can we get actually the support and agreement of the majority of the core, and that's certainly what we're aiming for. And we still think we're going to get it.

And that ball is still advancing. Okay, all right. Perfect. Thank you, guys.

Our next question comes from Craig Shere of Tuohy Brothers. Go ahead sir, your line is open.

Congratulations on a much simpler reporting structure now.

That's correct.

So in line with thinking about apples-to-apples comparisons, the backlog inventory maybe getting a little confusing from before the MLP roll-ups as we think about including acquisition related CapEx that was significant to the economics of that. And now capitalized overhead. Can you all give a range of maybe what incremental undisclosed growth CapEx you think is needed to roughly underscore that 10% CAGR at this point through the end of the decade?

I'll answer the question on the backlog first. We included -- we did a high probability share of the Hiland backlog, and included that in the project backlog because that is future capital expense that we'll be incurring to build those projects. We did it similarly when we did APT, and also when we did Copano. So that's not really a change. The overhead thing, look, apologize for the noise here and we won't do this again. But we just needed to get things on common terms. The way we describe projects, the way we make investment decisions, and the way we represent them in the backlog. And so now we're there. We'll do that that way consistently going forward. And we do expect with a combination of -- that a combination of acquisitions and additional capital beyond what's in the backlog will be required in order to meet that 10% growth. And that has been true really since we announced the role up transaction. And we still believe we're going to get it in sufficient amount to make it. What we have done with the backlog is really try to show you the stuff that we think of as high probability. We had the noise with the CO2 new source development coming out, but we try to show you the high probability. We don't show you everything that we think will ultimately get done or ultimately make high probability, but we do take that into account when we're putting our outlook together.

And as we look at that outlook, we feel very comfortable that we will have the capital expenditure opportunities necessary to drive that 10% growth. Plus, [indiscernible] the middle thing here that you just can't say too much is that notwithstanding this tremendous drop in commodity prices, the Kinder Morgan game plan is still on track. We still expect to be able to grow the dividend by 10% per year off of this $2 base, and to be able to have substantial excess coverage on top of that. And we aren't seeing anything that would degrade that outlook at this point. I think the proof of it is the numbers that Kim gave you for how much excess coverage even in these tumultuous times we expect to have. And all that's a function of the footprint the quality of the assets, and the fact that overwhelmingly we're a toll road, a fee-based business, and that gives us just a lot of heft and advantage in this kind of environment.

Understood. A quick question on the UMTP moving to a batch product opportunity. If that does go off, and that would be great if you're able to finalize that, but does that reduce some of the further downstream maybe fractionation opportunities if you start moving depending on the amount of pure product?

That would be right. If we're moving purity product, then it would require less fractionation capacity to be subscribed and built in Mont Belvieu or in Houston, in the greater Houston area. Again, we don't how much that mix will be. So what we're talking to market about right now, ethane is not a purity product that we would be batching. But otherwise propane, the butanes, natural gasoline, condensate and the y-grade. We are out there talking to customers about the ability to batch each of those products. And as you point out, depending on what the mix is of demand for y-grade versus the purity products will determine how much additional downstream fractionation capacity would need be to be built.

And that was always intended to be kind of all in one service offering to some degree right?

Well what we had -- we had an arrangement with one of the fractionation operators in the Mont Belvieu area to provide that service, and potentially participate in providing that service with them. But that was always I think looked at as an add-on if it came about. So it's separate and apart from what the UMTP conversion project itself is.

Okay. So the underlying economics wasn't relying on that in any way, including the cost of the --

Absolutely not. The pipeline always stood on its own two feet, and we never -- we always considered any fractionation or other downstream opportunities as add-ons that would stand on their own two feet.

Great. And last question on EOR, any update on when or what it's going to take for Katz and Goldsmith to get on their original trajectory plan? And Yates continues to decline. Any further thoughts on the NGL flood there?

I think first on Goldsmith and Katz, I think we understand the issues on conformance that we've got plans in place to take corrective action on those. 15 will be below plan, once you get the conformance issues resolved, it's going to take six to eight months to do that, the production come forward. So I think we've got it identified and have a plan in place for those. On the hydrocarbon admissible, it's still very early. We're evaluating the preliminary results and looking at the broader group, so not firm update there but it’s still in its early phases.

I think the important thing here is that we -- our people believe that the oil is still there. The oil in place is still there, it's just a question of getting it out. And if you recall, on Katz specifically, back when we started we said we would eventually peak at around 6,000 to 7,000 barrels a day. And notwithstanding we're under plan right now, we're well above last year and we're up to about 4,000 barrels a day now. And believe that will ramp up considerably between now and the end of the year. But we do not believe it will hit the plan. Now the other side of the coin is that SACROC is having enormous success, up 13% year-over-year, and that's allowing us to be very comfortable with our overall volume picture. Even versus plan. But we are working on Katz and Goldsmith to improve the production there.

Understood. Thank you.

The next question comes from John Edwards of Credit Suisse. Go ahead sir. Your line is open.

Nice numbers here again. If you could update us on the CapEx spend for the first quarter relative to -- what it is, I just couldn't find in the release. And then what is relative to budget. And then just the second question is, are you guys still affirming the 10% dividend growth through the end of the decade?

Well I'll answer the last question, and then I'll have Kim answer the tougher question to reconcile the CapEx for you. But the answer is emphatically yes. We are still affirming our target of $2 this year, 10% growth compound out through 2020 and in case any of you don't have your HP12 in front of you, that's $3.22 in 2020 just at that level. Obviously, we would hope as some of these capital projects and acquisitions come to fruition that we could do better than that, but certainly that's our target and believe that that is certainly attainable. We haven't seen anything that would change our mind on that. And that's with substantial excess coverage on top of that. Now, Kim, on CapEx for the first quarter, I think you said that. Didn't you?

Yes. So from a cash perspective, we spent about $800 million. Now if you look at the accrual, so it's slightly different. That's going to be closer to $700 million. But more importantly, I think is the numbers for the full year, and so if you remember correctly, our budget was $4.4 billion for the year, and that did not include the Hiland acquisition. So if you included the Hiland acquisition on top of that, we would've been at 7.3 and that's about where we are right now at 7.3. And essentially, what's happened is that we took some projects out in the CO2 segment and then we've had some spending moves a little bit in products. And then we've added to the CapEx as result of Hiland and so we're down about $100 million or so, but it's very close to budget.

Okay, great. That's helpful. That's all I had. Thanks.

Our next question comes from Christine Cho of Barclays. Please go ahead. Your line is open.

Just a broader question on M&A, the conversations that you've had with potential sellers in the last couple of months, how important is it to them to receive cash versus the stock of any potential buyer?

I don't think we've seen any preference one way or another. You would think that under certain circumstances some of the potential acquirees would want cash to strengthen their balance sheet for other opportunities. But I don't think we've seen a drastic preference one way or another. Dax?

No, I think every situation is different. I wouldn't call a dependency on way or the other. Every situation is different depending upon, as Rich said, liquidity needs also, tax comes into play sometimes on whether somebody wants carryover basis or how adamant they are about that, what their tax basis is. But there's not any -- I wouldn't say that there's any sort of trend one way or the other.

Okay. And then when I think about with your credit metrics, it would be I would think a little difficult to raise cash through debt for you guys. So how do you think about funding any transaction if the buyer wants cash? With something like Hiland, it was obviously easy enough to do that through your ATM program. But would you be more inclined to do those sized sorts of deals or where you can lean on your ATM program with no problems? Or are bigger size deals on the table even though it might require a sizable overnight offering?

I don't think that -- if we have an acquisition that we think is accretive and as a good strategic transaction, I don't think that funding that transaction is going to be an impediment to getting it done.

Okay and then your comments about batching the UMTP line. Is the increased interest in batching because the producers are already committed to fractionation up there, and so they don't want to commit to fractionation in the Gulf Coast? Or is it because producers have already committed their ethane and maybe some of their propane to other projects?

I think it's more -- my sense of it is that it's more that they just like the idea of having the flexibility. Because they don't know precisely what the future holds for them.

I think that's right, Steve. And then the optionality gives them a chance to extract more value out of their projects, it makes them more interested shippers. So I think it's a great option for the producers and shippers to get the most out of their product.

Okay. And then last question, if you keep TGP in gas service, how much capacity would you be able to offer from north to south service? And I would think that producers would be very interested in that capacity, so are they pushing you for a timeline?

I'll start and Tom can finish. It's not as big as our back haul projects have been to date. So it's maybe a couple hundred million a day. And it would take CapEx to get that all the way south. And so this is not like, hey, we can just hold an open season tomorrow and for $0.50 or something we can move it south. It would really take some CapEx, and it would take a relatively significant [indiscernible] to justify it. But the production up there is still growing, and if -- we would prefer to do UMTP because it could allow us to deploy more capital at a very attractive return. This is really just an option that we continue to have if customers are not ready for UMTP. But you can't think of it as just it's an easy back haul, it would require some CapEx and some customer sign-up to justify it.

When do you guys expect to make a decision on UMTP?

It's been a rolling three months, but we have structured our development activity in such a way that our spend there is manageable. And so we don’t have a specific time frame that I would give you right now.

Well, I guess to get it into service by ‘18, when would you have to make a decision?

Oh, I see.

We would like to have an open season mid-year this year. Now the complication there is we have to have agreements with what you’re shippers want, what’s the source, what products, how would they batch, and so those discussions are going on now. And depending on how they go, we’ll schedule an open season as quickly.

And you remember, of course, the conversion process we filed and it takes about a year, so we would expect the first quarter of next year before we have the FERC approval. But in the meantime, we’d like to do the open season, which we’ll probably launch in the second quarter and actually pin down the shipper interest which has been considerable. But again, we are a very conservative company, and until we have signatures on the dotted line we’re not going to commit to build a project or put it in our backlog.

Okay, great. Thank you.

I’m showing no further questions at this time

Okay. Well, thank you very much. Again, we think we had a strong first quarter. We look forward to a good year, and we appreciate your attention today. Thank you.

This concludes today’s conference. Thank you for your participation. You may now disconnect.