金德摩根 (KMI) 2014 Q4 法說會逐字稿

Welcome to the quarterly earnings conference call. At this time, all participants are in a listen-only mode. (Operator Instructions)

Today's conference is being recorded. If you have any objections, please disconnect that this time. I would now like to turn the meeting over to Mr. Rich Kinder, Chairman and CEO of Kinder Morgan. You may begin.

Okay, thank you, Sharon, and welcome to the investor call. As usual, we are making statements within the meaning of the Securities Act of 1933 and the Securities Exchange Act of 1934. I will make some introductory remarks. Steve Kean, our Chief Operating Officer, will talk more about operations and our backlog.

Kim Dang, our CFO, will review the numbers for the fourth quarter and full year 2014. And Dax Sanders, our Vice President of Corporate Development, will talk about an acquisition that we just announced this afternoon. And let me just start by summarizing very briefly that acquisition. We think it's a very exciting and strategic acquisition that we announced by separate release this afternoon.

We are acquiring Hiland Partners which is a large, privately owned midstream company, with crude transportation and gathering assets, and gas gathering and processing assets, primarily in the Tier 1 sweet spot acreage of the Bakken formation. It's overwhelmingly fee-based and it gives us the platform for further growth in the Bakken where we currently have no asset. We think we can to do in the Bakken the kind of expansion that we did on our Kinder Morgan crude and condensate system down here in the Eagle Ford, which has grown from less than 50,000 barrels a day throughput to having virtually all of its 300,000-barrel-per-day capacity contracted for in future deliveries.

So think of what we are doing as building a spider web that we intend to expand over the coming months and years. The consideration for the purchase is $3 billion including approximately $1 billion of assumed debt. We have a bridge loan commitment to finance the remainder, and longer term we will finance that remainder with equity and debt to maintain our appropriate level of debt to EBITDA ratio previously communicated in both the rating agencies and to our equity investors.

The transaction will be modestly accretive to DCF per share in 2015 and 2016 with the accretion ramping up thereafter and it is supported by long-term contracts with the system's largest shippers. That's an overview and Dax will give you more details in just a few minutes.

Let me get back to 2014 and the outlook for 2015. As you know, we closed the merger of all that Kinder Morgan entities into KMI during the fourth quarter, and so that made for somewhat of a noisy quarter post closing. But bottom line, our DCF per share for the quarter was $0.60 and we have declared a dividend of $0.45. That leaves excess coverage for the quarter of $320 million.

Looking at a $0.45 dividend, that's a 10% increase to the fourth quarter of 2013, and means that we will have distributed dividends for the full year 2014 of $1.74 per share versus $1.60 in 2013, and $1.72 in our plan. We were negatively impacted to a certain extent in the quarter by lower commodity prices primarily in our CO2 segment. But we were still able to produce strong results, and in my judgment that shows that our toll road-like assets perform well even when prices for underlying commodities are extremely volatile.

Looking to the future, we said when we announced the merger of all the Kinder Morgan entities back in August of 2014 that we expected to be able to declare dividend of $2 for calendar year 2015, to grow that dividend at a compound annual rate of 10% out through 2020, and to have more than $2 billion of excess coverage over that period from 2015 through 2020. We are still comfortable with the first two projections.

And we are still comfortable that we will have substantial excess coverage, but I have to admit it's hard to ascertain exactly what that amount will be given the recent volatility in commodity prices. But as an example, and an effort to be as transparent as possible, let's just take a look at 2015. When we released the outlook in December of 2014 for the year 2015 we based it on $70 oil and $3.80 gas. That's what we assumed when we did our budget back in the fall of 2014 and it represented the forward curves at that time.

We projected $2 declared dividend for 2015 and that's up 15% from $1.74 in 2014, and we said we would have, quote, over $500 million, end quote, of coverage. As we refined our budget, the actual coverage number in our budget is much greater. It is $654 million to be precise at those prices that I just mentioned.

Now in this world of lower commodity prices, we've looked closely at the impact on our excess cash and found it to be about $10 million per $1 change in crude price, and that's about $7 million in our CO2 segment that you heard us mention time and time again, pretty consistent from year to year, and about $3 million throughout all of our other business segments in the Company.

In addition, we think we have sensitivity of about $3 million for each $0.10 change in natural gas prices. Like everyone, we are unable to predict exactly where the prices will be for 2015, but you can make your own estimate and see that almost under any circumstances we have substantial excess coverage, and I think relatively little sensitivity compared to a Company that will produce about $8 billion in earnings before DD&A.

In an effort to be even more transparent, and without predicting prices at all, let me just take you through an example. Let's say you want to take our outlook and say, I believe we are going to have an average of $50 WTI crude price this year and an average of $3.20 on Henry Hub natural gas prices. What would that do to this $654 million of excess coverage on top of the $2 dividend. You would start with the crude, and you would say crude is going down by $20 a barrel. Our sensitivity is $10 million per $1, therefore, that is a $200 million degradation.

On the natural gas side, if we went from $3.80 to $3.20 that's a $0.60 degradation which would be six time $3 million or $18 million. That gets you to a total of $218 million. You take that off the $654 million and you have $436 million of excess coverage still there over and above paying a $2 dividend. Let me be real clear.

There's, obviously, a myriad of factors beyond price that influence the accomplishment of any annual plan. But I would emphasize that the commodity sensitivities that I just outlined do not -- do not -- include the positive impact of cost reductions in our CO2 EOR operations, which we are working on and believe will happen, and would certainly happen back in 2008 in 2009, the last time we had a dramatic change in crude oil prices to the negative.

So hopefully that gives you some guidance and rather than us trying to redo numbers, you can do your own figuring off of the outlook we gave you back in December, but the bottom line message from me would be that we still have lots of excess coverage. And you can roll that forward to other years and talk about exactly where the excess coverage is, and it gets even more difficult, obviously, the further out you go because who knows what the prices will be then.

But I think the main thing is this kind of toll road structure that we have allows us to survive and prosper very nicely even in a low commodity price environment. When I am finished Steve is going to detail our current backlog of projects which remain very strong. And this backlog is to me a clear indicator of future growth and cash flow at KMI. Let me close my part of the presentation by addressing succession planning at Kinder Morgan.

I have said publicly for some time that our Kinder Morgan succession plan called for Steve Kean to succeed me as CEO with me continuing as Executive Chairman. We now expect the change will take effect on June 1, 2015. Let me make a few points for you.

First of all, I can assure you this is not going to change in any way the way the Company is being run. Secondly, my name is on the door and I don't plan to go anywhere. The office of the chair will still consist of Steve, Kim and myself and post June 1 I will still be involved in all major decisions including acquisitions and expansion projects.

I want also assure you I have never sold a share of my KMI stock and I don't intend to do so in the future. So to kind of sum that area up, as we say in Texas, I plan to die with my boots on. But more importantly, Steve, Kim and the rest of the management team are doing a really outstanding job now, and I can issue you they will continue to do so in the future and that this Company will continue to grow and meet its commitments to its shareholders, its customers and its employees. And with that, I will turn it over to Steve.

All right, thanks, Rich. And briefly I want to say I am honored to have the opportunity, particularly coming from Rich, who is one of the best and most accomplished CEOs in America, who by the way still has his boots on. I'm also ready and committed and determined to do my part here.

I'm excited by the opportunity, but there's no reason for any of you to be. As Rich said, you can count on his active involvement and you can count on Kim and me, the leadership team here, and our 11,000 co-workers to run this great network of assets safely, profitably and reliably every day and to continue to grow the Company.

So this will be the most seamless transition in the history of corporate America. So now let's do the quarter. Backlog first and then a segment update. On the backlog, since her investor conference in January of 2014, we have grown our backlog by nearly $2.8 billion. Our current backlog stands at $17.6 billion which is down slightly from the last quarter.

Over the quarter, we added $1.24 billion of projects while we put into service $730 million worth of projects for a net addition of about $500 million. But the impact of lower commodity prices led us to re-examine our CO2 investments, and we removed from the backlog a little under $800 million for the quarter, and the majority of that came out of the backlog for the CO2 segment. The additions to the backlog were in our Pipelines and Terminals businesses.

The largest being the addition of the Palmetto refine products pipeline serving the southeast US. That project includes the pipeline. It also includes an upstream expansion of the Plantation Pipe Line system and associated terminal investments and the total to our share, assuming others opt in for their shares, would be about $800 million.

The additions to the Terminals and Pipelines backlog underscore the continued strong demand for our midstream energy infrastructure. Now a brief segment review, and I'm going to focus on the performance on a full-year basis compared to 2013. In Gas, earnings before DD&A were up $352 million, or 9% year-over-year, to $4.069 billion. The Gas segment benefited from a full year of the assets that we acquired from Copano, including some growth in those assets, as well as strong performance from our Tennessee and El Paso system.

We continue to see strong demand for long-term firm natural gas transportation capacity. So even in this fourth quarter that we just went through, we added another 242 million cubic feet a day of long-term transportation commitments with an average term of 12.8 years. So if you look at the total going back to December of 2013, since that time, over that 13 months, we have 6.7 Bcf of new impending commitment with an average term length of 17 years.

That's about 18% of the capacity of the underlying pipeline system those commitments are associated with. We expect the demand to continue, as I think we are still at the beginning of what will ultimately be needed, both for power generation and industrial and [petchem] load. We are also seeing improvements in storage opportunities.

I think first in the current market but also in terms of the long-term commitments. We got a firm long-term commitment to 3 Bcf of storage on our Texas intrastate system by and LNG customer during the quarter, and I think all this on transport and storage side points to continued optimism about the overall value of our gas network.

CO2 segment earnings before DD&A were up $26 million or 2%. But looking at the fourth quarter on a year-over-year basis, this segment was down 6%. So clearly we faced deteriorating commodity prices in the fourth quarter. But operationally, we saw a record year at SACROC which was up 8% year-over-year, and was averaging 35,500 barrels a day in the fourth quarter and record CO2 volumes in NGL production.

Yates was down slightly, 2% year-over-year, and although Katz and Goldsmith are up on a full-year basis both continue to perform below plan. But in total, oil production is up due to the out performance at SACROC which is our biggest field. As I said, we reduced our backlog in this segment while we continue to have many good investment opportunities here. We will lay some of those out at the conference.

We delayed plans on various new developments including the St. John's field and associated pipeline infrastructure with that development. Turning to Products, segment earnings before DD&A on a full-year basis were up $76 million, or 10%, with strong year-over-year growth on KMCC and SFPP more than offsetting a decline in our transmix business. The key operational developments in this segment are improved refined products volumes and a ramp-up in crude and condensate volume on KMCC.

All refined product volumes, gas and diesel and jet, were up in 2014 versus 2013. Including Plantation, gasoline volumes were up 4.4% for the full year versus 1.5% without Plantation and 1.1% for the EIA. Much of the full-year difference is due to Plantation, therefore, but in the fourth quarter we saw gasoline volumes on SFPP, our West Coast system, up 4.4% year-over-year and what we believe is a sign of economic improvement in the markets we serve, and also, in part, perhaps the beginning of a demand response to lower prices.

From a project standpoint in Products, we are experiencing a further delay in our Houston ship channel splitter project on the KMCC system. We now expect March of 2015 in-service. On the other hand, our various build outs of the KMCC system are going very well, with several of them coming in ahead of schedule and/or under budget. And I already mentioned Palmetto, which had a successful open season in the fourth quarter and was added to the backlog.

In Terminals, segment earnings before DD&A for the year were up $181 million, or 23%. The growth was split roughly two-thirds/one-third in favor of organic growth versus growth from acquisitions. We continue to see strong performance in our Gulf Coast liquids business and benefited from the expansions coming online in Edmonton and the Houston ship channel primarily.

During the quarter, we brought online Phase 2 of Edmonton, two crude by-rail facilities, and our liquids terminal expansion for Methanex at Geismar, Louisiana. In this segment, we continue to see strong demand for liquid storage and handling, again, particularly in Edmonton and Houston. And nearly all of our $2.1 billion backlog in this segment consists of expansions of our liquids facilities, and, again, on the Gulf Coast and in Alberta. On Canada, segment earnings here were down $17 million year-over-year. That was really a result of FX rates. Otherwise, this segment had a good year.

But the main story continues to be our progress on the $5.4 billion expansion of Trans Mountain. That expansion is under long-term contracts. As you will remember, they have been approved by the NEB. We filed their facilities application December 2013 and we are working through that process, under a schedule that calls for a decision in January of 2016. And we expect an in-service date late in the third quarter of 2018.

We continue to make good progress in our consultation processes. We also recently completed some important, though controversial, testing at Burnaby Mountain in greater Vancouver, and that will enable us to minimize impacts on local residents for the last few kilometers of our build. So that's it for the segment update and the projects. And with that, I will turn it over to Kim.

Turning to the attached page numbers to the press release, the first page is our GAAP income statement. As Rich said, it was a bit of a noisy quarter given the closing of the transaction about two-thirds of the way through the quarter, and we have got a number of certain items that are littered through the GAAP income statement. So I will turn to the second page, which is where we have these items delineated so that you can see them individually, and also is our calculation of distributable cash flow for KMI.

This is a new format for KMI. Previously, at KMI, we used the financial metric cash available for dividends. We have now converted KMI to the DCF formula we previously used for KMP and EPB which is net income plus CD&A including our share of joint venture DD&A, plus booked taxes minus cash taxes minus sustaining CapEx including our share of JV sustaining CapEx, plus or minus some other small adjustments.

This formula will work for all the periods presented, even those prior to the consolidation transaction, because KMI consolidates KMP and EPB, so net income at KMI includes 100% of earnings for all three companies. For periods prior to the fourth quarter of 2014, we subtract from our DCF formula the declared distributions we made to KMP and EPB public unit holders resulting in a number for DCF that it is equal to what we previously reported as KMI's cash available to pay dividends.

For the fourth quarter, there will not be distributions made to KMP and EPB unit holders because the transaction closed before the fourth quarter record date. So there will be no MLP distributions to subtract, however, the KMI shares that we issued in November will receive the full KMI fourth quarter dividend, so in our average shares outstanding for the fourth quarter we show the newly issued shares as outstanding for the entire fourth quarter. So with that explanation of the overall format and the new format, let me take you through a couple of numbers.

This is the format that we would expect to continue to use going forward. So DCF before certain items in the fourth quarter was $1.278 billion, that's up $796 million. You can see that the 2.133 billion shares outstanding, again, include the newly issued shares for the entire fourth quarter to get us to $0.60 of DCF per share available versus the $0.45 dividend.

For the full year, we are at $2.618 billion of DCF, up $905 million. Again, the weighted average share here is 1.3 billion shares include a full fourth quarter of the newly issued shares to get us to $2 in distributable cash flow before certain items versus the $1.74. The segments, I'm going to go through couple of numbers. Steve has taken you through a lot of the detail, but the segments produced earnings before DD&A of $1.972 billion in the quarter. That is up $98 million, or 5%, with the big contributors to that being Gas up $51 million, or 5%, and Terminals up $56 million, or 25%.

For the full year, segment earnings before DD&A, up $613 million, or 9%, with the biggest contributors being Natural Gas Pipelines up $352 million, or 9%, Terminals up $181 million, or 23%, and Products Pipelines up $76 million. Now versus our budget for the full year, Natural Gas Pipelines came in above their budget. They are about 2% above their budget primarily because of incremental transport revenues on TGP and EP&G.

CO2 came in about 6%, or $90 million below its budget, primarily due to lower oil prices and a higher [mid-CUSH] spread, and also some higher expenses in our Goldsmith field. Products came in about $68 million below its budget, primarily because of volume, lower volumes on KMCC, a lot of which we will receive revenue in later years, make-up revenue, and the delay in the splitter. And then, Terminals came in about $10 million above its budget as a result of the APT acquisition.

Without the APT acquisition, Terminals would have been below its budget because of some lower coal volumes, expansion delays, and negative impact of FX. The certain items in the quarter totaled a $98 million loss. The more significant ones were the $235 million impairment on our Katz field, primarily, or all due to the lower price curves that we have to use in that test. Then we also had a benefit that offset that, a non-recurring tax benefit of about a little over $100 million. So that is it for the DCF page for KMI for the quarter.

Looking at KMI's balance sheet, and comparing that, the December 2014 balance sheet to the December 2013 balance sheet, you can see the impact of the transaction primarily in four of five different lines. In deferred charges and deferred income tax, what's happening there is KMI was previously in a deferred tax liability position because of the step-up on the transaction, and the [bate] tax basis that we are getting the assets, we actually now have a deferred tax asset and so you see a big swing between deferred income taxes and the asset deferred charges.

You also see a big increase in other shareholders' equity and a reduction in non-controlling interest as the public unit holders at EPB and KMP went away and we issued new KMI shares. The other large change is debt which I'm going to reconcile for you in just a minute. We ended the quarter with $40.6 billion of debt, which is about 5.5 times debt to EBITDA, relatively consistent with where we expected to end.

Our debt is up $5.1 billion for the quarter, and so let me take you through those -- the larger changes contributing to that. The consolidation transaction was a cash outflow of about $4.06 billion. That was $3.9 billion for the cash portion of the deal plus associated fees. Expansion CapEx, acquisitions, and contributions to equity investments were about $1.1 billion in the quarter, and then we made a CPC settlement payment of about $319 million for a cash outflow of $5.5 billion.

We raised equity prior to the close of the transaction at EPB. There was ATM of $126 million, and then we have about $250 million cash inflow from other items are working capital source, which is primarily the coverage that we generated in the quarter. And that gets you to the $5.1 billion. So with that, I will turn it to Dax.

Thanks, Kim. Just to reiterate what Rich said, this is an acquisition that we are very excited about as it will give us a premier asset in a premier basin. At this point, we have a significant presence in every major producing region in North America except the Bakken. With this acquisition, we will now have a major position in the Bakken and a long-term partnership with some of the most prolific producers in the Bakken including Continental Resources.

To give you a bit of detail on the transaction, it is, again, approximately $3 billion in total enterprise value. Very slightly accretive out of the gate but based on our assumptions it should be $0.06 to $0.07 accretive a couple years out. Working through the lens of 2015 expected EBITDA, approximately 86% of the margin is fee-based with the remaining 14% subject to commodity exposure primarily through POP processing arrangements in the gas processing and gathering segment.

There are essentially three main businesses to (inaudible.) The first is oil gathering which consists of four facilities and represents approximately 59% of the EBITDA and is almost exclusively fee-based with really no direct commodity exposure. Hiland serves most of the major producers in the Bakken and has over 1.8 million acres dedicated with a large piece of that centered at what many consider to be the Tier 1 portion of the Bakken, as Rich mentioned.

The second is oil transportation which is essentially the Double H pipeline. The Double H represents approximately 27% of the 2015 EBITDA and is 100% fee-based. The Double H is a 485-mile pipe extending from the [Duor] Terminal in McKenzie County, North Dakota along the North Dakota/Montana border down to Guernsey, Wyoming where it ties into Pony Express.

It includes 500,000 barrels of storage in two trunk stations. It's in the process of being commissioned right now with the initial capacity being approximately 84,000 barrels a day, but increasing to approximately 108,000 barrels a day beginning next year. (Inaudible) firm commitments for approximately 60,000 barrels a day with an open season in process right now for additional barrels, again, currently in process. As of Monday, Double H had nominations for approximately 80,000 barrels for February which is its first full month in operation.

The third business is gas gathering and processing which consists of five different facilities and represents approximately 14% of the EBITDA. It's almost exclusively non-fee-based or commodity exposed through the POPs that I mentioned earlier. Again, the largely fee-based nature of these asset limits our direct commodity exposure -- exposure to commodity prices. However, it is certainly not lost on us that there is indirect commodity exposure in that the economics of these assets are in part dependent upon whether the oil behind them continues to be produced.

We believe that the risk of the oil being produced is largely mitigated by the quality the acreage that is dedicated to Hiland and will be driving the economics of oil gathering. As we mentioned in the release, the acreage driving our economics is largely located in McKenzie, Mountrail and Williams counties and represents some of the best drilling economics in the Bakken and in North America.

Consequently, we believe that this average is economic to producers even in the current commodity environment. Some Bakken producers, including some of our customers, have publicly revised their guidance for drilling and CapEx in recent weeks to account for the current commodity environment and we have taken that into account in our analysis.

Further, while nobody can really contemplate what will result from a substantial decline in commodity prices from here, the relative attractiveness of the acreage should position us well versus other acreage competing for a finite number of rigs in such an environment. Again, to summarize, we believe this is a highly strategic acquisition with some premier assets that largely fit our toll road concept and are located in an area where we have no presence. We will be inheriting a very talented group of employees that have built a great company and we look forward to doing great things with this franchise.

Okay. Thank you, Dax. And, Sharon, if you will come back on now we will take any questions that our listeners may have.

Thank you. (Operator Instructions) Shneur Gershuni of UBS.

Rich, first wanted to offer congratulations on your accomplishments and, Steve, also wanted to congratulate you on your upcoming expanded responsibilities.

Well, thank you, you are kind.

Just a couple of quick questions here. I was wondering if we can talk a little bit more about today's acquisitions. You have had a lot of pundits out there talking about the Bakken with production being flat at best, possibly declines and so forth.

I was wondering if kind of the opportunity over the next couple of years, as you see accretion pick up, is that a function of moving some of the trucking volumes onto the pipeline system? Is that how we expect to see the opportunity on a go-forward basis given the bleak environment that we have out there for the Bakken?

Again, let me start with this, and I'm not sure if we posted this on the website, but if not, we should have. If you look at acreage around the country and what the break-even price is based on WTI prices, this area of the Bakken is right at the top of the list. It is one of the two top producing basins in terms of break-even prices. So we don't think that it is nearly as bleak as other parts of production are, if you want to use that word.

Secondly, obviously, a big part of the upside is the ramp-up in this Double H pipeline. We are starting out in the 80,000-barrel-per-day range, ramping up to beginning next year 108,000. And, again, we believe that the combination, and as you may know, there's a joint tariff arrangement between Double H pipeline and the Pony Express line that gets you all the way to Cushing. And then, of course, there are several avenues now to get from Cushing on down to the Gulf Coast.

We believe by putting all that together we provide by far the most economic way of getting barrels out of this very sweet spot in the Bakken. So we think HH is a real winner both near term and long term, so that's part of it. The other thing is that we have looked at the EURs on these wells. We've looked very carefully at the drilling plan of our largest customer, and we have adjusted for exactly what they plan to do, what we believe they plan to do with the rig counts that have already been announced.

So we think we've been pretty conservative in the way we have assessed this, and believe that it's an incredible asset for us. Let me say that beyond that I think we have the opportunity, as I said in my opening remarks, to do here kind of what we did in the Eagle Ford on KMCC, and that is to build out this system, to make it bigger, to do some acquisitions, to do some extensions. And the fact that we have about 1.8 million acres dedicated to us, I think, shows -- will show very well in the long term.

You have to look at this in the long term, not in the flavor of exactly what's happening today. We think -- long-winded way of saying -- we think we have been very conservative in looking at the front end of this transaction and still think it has enormous long-term growth potential.

Okay. And just to follow-up on that, in terms of permanent financing plans, any sense on an equity to debt ratio that you are thinking about?

Yes, we've been very clear since the time we announced the merger last August after meeting with the rating agencies that we would stay in that band of 5.5 to 5.0 debt to EBITDA and certainly driving that down toward the lower end of the range as we move on out toward 2020. We've been very consistent on that, and we have said that the Holy Grail for us is maintaining our investment grade rating.

Great. And one final question, you had mentioned in the prepared remarks that you had taken out a little under $800 million from your backlog out of the CO2 business due to lower commodity prices. I was wondering if you could share the commodity price that you would assume to take that out? Was it $70, was it $50, just trying to understand the sensitivity to see if that is possibly going to change on a go-forward basis given where crude prices are today?

I don't have a specific price for you, but what we did, and in a lot of cases what we were doing is delaying our expectation of making these investments, and in some cases that was delaying it outside of the five-year window that we typically use for defining the backlog. We're going to give you at the conference next week some more specific return numbers to go with, various development activities that we have going on. But I think the way to slice it is, it is very economic for us to do CO2 development and pipeline work where we are expanding off of our existing footprint.

So like southwest Colorado with Cow Canyon and the Cortez pipeline, particularly the north part of that, expanding that to make that available. And it is certainly very economic for us to be doing infield drilling in SACROC and additional HDHs at Yates, and so the kinds of things that are building off of and utilizing our existing infrastructure are very economic. If you have price recovery that's back in the $75 range, I think you would see some of those projects that we pushed out or pushed off coming back on.

Great. Thank you very much, guys.

One other clarification, the $800 million, that was predominantly CO2, but there were a few other cats and dogs in there, as well, but it was predominantly CO2.

Darren Horowitz of Raymond James.

Hey, Darren, good afternoon.

Hey, Rich, good afternoon, and, Rich, and, Steve, congratulations to both of you on your respective announcements. Rich, just a quick question, and I realize you're going to get into a lot more detail on this next week, but I'm just curious with the current forward commodity curve, have you seen a big shift away from more producer push to more demand pull, or consumer pull-type projects?

And specifically, with regard to export opportunities around Galena Park, the ship channel, I know we've talked about ultras-low sulfur diesel exports, and, obviously, that big tank expansion that you had discussed that was underwritten by a new shipper, but am also thinking about more of an emphasis on Pasadena in addition to Galena Park, a further BOSTCO build out, more ability to get more product on the water quicker?

I will turn that over to John Schlosser, who runs our Terminals group.

We are looking at 35 million barrels right now. We have six different projects we're working on that will bring it up to 41 million barrels. We are going from eight docks to 11 docks, so we feel we have the premier footprint in North America for clean products and we see more projects and more growth opportunities in that area as we go forward here.

In terms of aggregate CapEx, and maybe it's too early to do this, but can you put a rough cost number on that, and is it fair to assume unlevered cash-on-cash returns may be in the low- to mid-teen range?

Yes, we are managing actively right now a little under $2 billion worth of projects on the Houston ship channel between BOSTCO, Pasadena and Galena Park and some of our other expansions. And the returns are all in the low- to mid-teens.

Okay, and then last question for me --

Subscribe over term contracts from our customers. It's not like we are building tankage on spec here.

Sure, sure. And then, Rich, last question for me, maybe, as you're looking at the existing the opportunities that, obviously, with the challenges across natural gas, natural gas liquids and crude oil prices, in terms of cash-on-cash returns are the best bang for your buck with regard to allocating capital, is this the biggest area of opportunity for you?

I think we've got opportunities across the board. I said last August when we announced this that what we would have is a much lower cost of capital under the new arrangement, or a lower hurdle rate, if you will, which, again, on that for tax basis is about 3.5%. Not that we're going to do 4% projects, but it gives us a lot more leeway to make accretive acquisitions, and we are certainly going to use that currency to make it acquisitions.

And I think that if there is a silver lining in these clouds of low commodity prices it's going to be the ability to make some extremely good acquisitions over the next six to 12 months. We are not the only player here that's going to be looking at the same thing. There are other well capitalized midstream companies, but I think you're going to see consolidation opportunities. And everything I said last August, I think, is even more true today than it was then given the decline in prices.

Thanks, Rich.

Brad Olsen of TPH.

Hi, Brad, how are you this afternoon?

Hey, good afternoon, Rich. How are you?

Good.

My first question is really just a follow-up on some of these others on the Hiland acquisition. You guys mentioned that there would be some incremental CapEx, and I'm just trying to understand where that CapEx is going to go. Is there additional construction left on the Double H pipeline or is that further building out the crude gathering or the G&P asset footprint?

I'll ask Dax to answer that.

Yes, Brad, we think that we will be able to invest roughly $850 million from, call it, 2015 through 2018. There is an aggregate of oil well connects, some gas well connects remaining CapEx on the Double H.

The Double H has roughly $30 million left to spend and a little bit more than that to spend to get it up to roughly the 108,000 barrels. Now what that doesn't contemplate at all is the substantial expansion of the Double H, which is something that we will certainly be putting some time and thought and opportunity into. But that gets us up to the 108,000 barrels a day.

Got it. And so, safe to say that the vast majority of the remaining $800 million is gathering and processing and crude gathering?

I think that's right.

Okay, got it. And when you think about the competitive environment in the Bakken, some other midstream operators have made asset acquisitions up there over the last few years, and when you think about what percentage of the market is spoken for under long-term midstream agreements and what might still be up for grabs, do you see an opportunity to attract incremental customers?

I guess what I would say is, as we mentioned in the release, we have got good, long existing relationships with a lot of different customers including some. very prolific producers up there, but we don't have them all. We have not necessarily, we, obviously, have really good acreage dedications with the ones we do have which makes us feel really good about this business, but there are some that Hiland doesn't have a historical relationship with that we do have a relationship with, and we will absolutely be spending a lot of time to try to solidify those relationships with the Hiland assets.

Got it. I guess, shifting gears a bit to the natural gas pipeline side of things, it looks like you guys are still pushing forward on the northeast direct project and I was wondering -- there been some press releases out about some of the work you are doing around multiple different rights-of-way, how is that process going? I guess from a simplistic view which is really the only view that I do. The simplistic view is going through New York state, moving along a right-of-way that is similar to Constitution which has become kind of a regulatory quagmire.

What seems to be a really encouraging project with a lot of customers who seem excited about it, that right-of-way issue kind of sticks out as something that could delay timing or cause problems. Is that point of view accurate or fair?

I don't really think it is, and let me tell you why. We have adjusted this right-of-way so that today the huge percentage of the right-of-way is along utility easements. There are certainly people who are going to say not in my backyard, but that's why we have FERC as an enabling agency, and we will have, in fact, we were going to have, I forgotten how many, open houses here in the next few weeks, actually this winter, in all of these communities talking about it.

But in the end we will have a route and we would expect the FERC to approve that route because it is reasonable and you have to look at the underlying economic need here. If there is one area of the United States that needs additional natural gas it is New England. And the area of New England, with this ending at Dracut is exactly the location where you need to be in order to serve that market, which initially will be LDCs. And you can see we have announced the LDCs in the past who have signed up.

We now have reduced almost all of those to PAs. And longer-term, of course, beyond the LDCs in the end the power generation market in New England has to have more capacity on pipelines. It just can't work any other way. And we plan to be there to catch that ball when it comes off the backboard. So I think we can do this.

We are proceeding very, in close consultation with everybody up there including our customers and including government officials. And I'm astounded sometimes, frankly, and this goes beyond this project, I'm astounded that even as recently as a couple of years ago people, I believe, the general public, rightfully believe that natural gas is the savior. It emits half as much emissions as other power generation alternatives, for example, and it's the lowest emitting fossil fuel, this is the bridge fuel for the future even if you believe that we will eventually move more to renewables.

And now we have a coterie of people around the country who seem to be attacking every expansion of every pipeline. And I still believe in the common sense of the American people and the regulators, and I think in the end projects that are really needed like this will get approved and will get built.

Let me emphasize that there's not one damn cent of that northeast direct project, either the supply portion or the market portion, that is in the backlog that Steve took you through. This is a project that we are working on and if it gets built it will be additive to everything we have projected for you thus far.

That's great color, Rich. I appreciate all the color, everyone. Thank you.

Carl Kirst of BMO Capital.

Carl, how are you doing?

Good afternoon. Good, good, thank you. And certainly congratulations to both of you. Just, maybe if I could stick with NED for a second because I'm just curious now from the other aspect, from the commercial aspect, is there any better sense of how the market is shaking out from the demand pull aspect, id est, what perhaps Maine might do to push you over the finish line or anybody else for that matter?

I will let Tom Martin, who runs our Natural Gas Pipelines answer that.

Thanks, Rich. As Rich said, we have gotten most of our LDC part of this project sewn up, so it is really is going to the state of Maine and ultimately the power customers that will be the next phase. And we think over the next quarter, maybe two at the most, is we will have a very clear picture on getting those commitments in place to, we believe, to move forward with this project.

But a lot of work to be done between now and then, certainly need to work with the state and local officials, as well as the commercial aspects of these transactions. But as Rich said, all the people that need this commodity have been very positive towards this project and we are very optimistic that we'll get this done.

Understood. So it sounds like the spring is still at least a -- potentially still a realistic scenario as far as knowing how the chips are going to fall?

Spring into mid-year, yes.

Okay. If I could ask a question on the CO2 business only because, Rich, I think you mentioned that the current budget, for instance, does not include any the potential benefits of cost reductions, and I'm just curious in the experience of 2008 and 2009 if there's any sense of magnitude of what that was back then as far as possible offset we may be looking at this year?

Yes, Jesse?

Yes, thanks. I think our target is going to be 15% of our total operating budget. Keep in mind, about 40% of that is tied to natural gas prices, or correlated to natural gas price which is power. So we're shooting for a overall 15% reduction in cost, roughly $30 million of the non-committed dollars. In regards to 2008 and 2009, we were able to achieve a little higher percentage of that, but what we have learned through that period is that we tied a lot of our drilling and well work programs and contracts to crude price.

So when we lowered the budget to 70 there was already a wedge out of that. So in aggregate it is probably going to be closer to the 20%, consistent with what we got in 2008 and 2009.

And, obviously, Carl, he is talking just about the O&M, the operating budget. There will also be savings on the capital side. But as far as impact on 2015, reducing the O&M costs, we believe 15% is a good solid number and they've already achieved about one-third of that with contracts they've already renegotiated just since the first of the year. So I think we will have that. Again, there will be a lot of moving parts, obviously, in this kind of environment, but we don't have that any place in our numbers yet.

Understood. And then lastly, if I could, this is just sort of (no audio) to 654, was that basically just a nuance to bonus depreciation at year end or was there something more going on there?

Kim?

Sure. That was just, Carl, when we went out with our budgets where all the pieces weren't in place yet and so we went with a over $500 million. It was over $600 million at the time. But one of the moving pieces was that we were finalizing some of the tax purchase price allocation. And so that's why we went out with an estimate as opposed to a precise number.

Understood. Appreciate the clarification. Thanks, guys.

Thank you, Carl.

Craig Shere of Touhy Brothers.

Go ahead, Craig.

Good afternoon. And congrats, Rich, and, Steve, and the whole team. When the market was questioning and not understanding as much a year ago you guys kept a steady sail and simplified things dramatically. Congratulations for a job well done.

Thank you.

Couple of questions here, on the EOR side, really great growth at SACROC. Yates was also up, I think, 6% sequentially. Can we get some more color on that and also the ramping trends at Katz and Goldsmith that maybe was behind schedule the last couple of quarters? And can you comment on appetite for EOR growth CapEx initiatives in the current environment with things like ROZ, or the Yates and [Jail Flood]?

Craig, we're going to go into a lot more detail next week at the analyst conference. In fact, I think Jesse has got a slide that is going to show you basically what returns are at various WTI prices broken out by SACROC, Yates, Katz, ROZ, so on. But I think the huge success story here is SACROC and you are going to see next week that once again that if you have attended our conferences every year people ask, well, when does SACROC start this inevitable decline?

And I remember at one time it was going to be 2008, 2009, then it was 2014, 2017, 2018. We continue to move that out because, frankly, it is just a fantastic field and we're now doing a lot of infill drilling that is very economic. It is more economic than putting on new patterns by a fair margin. And, again, Steve gave you the average for the year and for the fourth quarter. We are starting this year right at 37,000 barrels a day at SACROC and our budget that we set for this year is about 33,000 barrels a day.

Not without moving parts elsewhere in CO2, but thus far, we are off to a very good start and it is largely due to SACROC. So we see that. Certainly, the ROZ, I think is at the upper end of the curve in terms of clearing price versus something like infield drilling at SACROC, and we will just have to see how that comes out. But certainly the money we are spending now on our test patterns there is economic given the costs we've already put in it, it's very economic on a going forward basis. And then we will just reassess after that on where the prices are. Steve, or, Jesse, anything else on that? They are nodding their heads, so I guess they are agreeing.

Okay, and just one more question. It would be great on an ongoing basis quarterly if maybe we could track the growth CapEx inventory or portfolio relative to what was originally envisioned when you issued your original guidance through 2020.

I realize there are some moving parts, including commodity prices, but where do we stand right now in terms of maybe needing just a couple billion dollars more at the same commodity prices you originally assumed to fulfill that long-term growth guidance?

Go ahead, Steve.

I was just going to say, I think that we can give you some more insight into that, but it's very hard to define what in, what some people have called our shadow backlog is going to fall into the backlog. But we believe we are going to get a substantial piece of additional CapEx beyond what we are showing you in the backlog, and our performance over the year and from quarter-to-quarter is generally demonstrating that to you.

The other thing that is hard to incorporate in there is acquisitions like the one we are talking about today. We expect we are going to see those, as well. So those are shots that are just little bit harder to call.

But you're making a good point. Certainly with some additional capital deployment in our existing businesses, we can claw back some of the damage done in our CO2 business from lower commodity prices. So we can help get back some of what would have otherwise been a deterioration from the transaction that we were talking about back in August.

Sure, I guess that was my point of just making up the free cash flow that was originally guided, and maybe getting to the point eventually of being able to increase that 10% CAGR on the dividend.

Well, yes, we would certainly, that's our intent too. And, again, as you can see, we have got a lot of positive cash flow even with lower commodity prices. It's just harder to judge in a going forward basis, but the reason I took you through 2015 is that something that I can get my pea-sized brain around so you can see that in a year like 2015, and I'm not saying that that's the same every year, but you can kind of see where you are and the impact of commodity pricing on the bottom line in terms of distributable cash flow and excess coverage.

Great. Thank you very much. Look forward to next week.

Good.

John Edwards of Credit Suisse.

Hey, John, how are you doing today?

Doing well, Rich. And congrats on your upcoming transition, I guess, well deserved.

It's going to work great. Steve is as good as they come. I'm going to be hanging around just to (laughter)

Well, congrats to Steve, as well. I'm just curious on the Hiland deal, if you can give us an idea of the economics behind the acreage that is dedicated. In other words, maybe what the break-even costs are for that acreage?

I don't know if we -- and I'm going to turn this over to Dax. Dax, I don't honestly know whether we have posted any slides on the website yet? I think we're going to. One that we used with the Board today I thought was very good. Dax, you want to just kind of take us through that?

Yes, absolutely. I think, John, a couple of things, a couple of sources. Generally, I think if you look at one source, I think, and this is publicly available, is a presentation that Continental Resources, who is a pretty well respected producer up there, put it on a website based on a presentation a couple weeks ago. And they show a graph that shows effectively a [PV thin] of, at a WTI price of effectively $40 and assuming a modest amount of cost cuts in this kind of environment.

So that's one piece of data out there that you see. And, again, that's in terms of a WTI price. We've got another piece of information from a bank that shows effectively Bakken Tier 1, Bakken being, if you look across different acreages across the United States, being really second only to the Eagle Ford Tier 1 and having a [PV thin] or 10% IRR break-even with a WTI price in the range of, call it, $35 to $45. And, again, that assumes some cost cuts that are probably appropriate in this environment.

But those are the types of numbers that we think about. Again, I think what you've heard all these producer say, a lot of these guys have said publicly is they are reducing rig counts, but they are high grading their portfolios and substantially increasing target the EUR targets in the wells that they are drilling and they are really focusing in on the higher grade acreage and focusing rigs on that acreage. And that's really kind of what we take into account in our analysis.

All right, that's really helpful. In terms of those ranges, is there is some percentage, I think you said it was 1.8 million acres dedicated, is there some percentage that, say, the economics are more at the fringe, say it's not economic below $60 or $70, I assume it's some kind of a curve in terms of how this shakes out?

Yes, I would just say that the majority of that acreage is stuff that we believe is concentrated in what we define as that sweet spot which is, again, the sort of McKenzie, Mountrail and Williams counties. So we think that's really kind of what's driving things.

Again, some touchstones for you, John, a lot of different people have a lot of a different opinions, but the North Dakota Department of Mineral Resources put out a report on January 8 that ranked the counties in North Dakota by break-even oil price. And the rankings, the three counties that we are primarily, where the heart of what we have is in, is McKenzie, Williams and Mountrail, and those were three of the top five counties in North Dakota according to the Department of Mineral Resources. And McKenzie has the most rigs, Williams has the second number of rigs, and Mountrail has the third largest number of rigs.

I think, certainly, when you have that much acreage, 1.8 million acres, some acreage is going to be better than others and they are not going to drill up everything. But certainly we think and believe that we are right in the Tier 1 sweet spot of the Bakken, otherwise we would not have done the deal. And the other thing is, we have got long-term contracts on this, so, again, whatever happens in that acreage we feel we are going to be able to benefit from it and benefit our customers for years to come.

Okay, that's very helpful. And then, you indicate it's a 10 times multiple by 2018, what's the multiples for 2015, 2016, 2017, if you can give that?

I think the only guidance we have there is that it is modestly accretive in 2015, and then we build to that 10 times by 2018.

Okay, all right.

It's accretive every year from the get-go, so I think that's the important thing.

Okay. That's really helpful. That's all I had, thank you very much.

Okay, thanks, John.

Chris Sighinolfi of Jefferies.

Good afternoon, Chris.

Hey, Rich, how are you? Thanks for taking my question. I just wanted to follow up on a couple of things. To follow up on things that may or may not be in the guidance, I know Carl followed up on some of the cost reductions that might be possible at the CO2 business. I was curious, you had mentioned in the fourth quarter the currency impact in Canada, just wondering if that was part of the later quarter scrub on what you're offering for 2015? I'm sure you are going to go into more detail next week, but was just curious about the widening Canadian dollar impact?

Sure, and we can go into this more next week, but what we have in the budget is 0.92 times up for the exchange rate.

Okay. And is there any sort of broad sensitivity, Kim, that you have offered on that?

We'll have that for you next week.

Okay, perfect. And then, Kim, you were kind enough on your last quarter call to offer detail on the hedge positions, and I think you had commented that you might add end of year end or beginning of the new year look to add additional hedge positions. Just curious if you did that, and if so, if we could get an update on where things stand?

We continue to add hedges. We have an ongoing hedge program. Right now we have got about 80% of 2015 hedged at about an $80 price, 50% of 2016 at a $79 price, 32% of 2017 at a $79 price. And 20% of 2018 at an $81 price.

Great. Okay. And, I guess, final question, maybe for Steve or for Rich. In terms of the CO2 business, I know there was the comment earlier about the CapEx that came out of the five-year plan, just wondering how we should think about the impact on -- potential impact on volumes? Rich, you had talked about the SACROC slide and the slide that you guys have about eventually when does that asset start declining, if and when? Just wondering how we think about in context of some of the CapEx coming out over the next five years, what perhaps we ought to be doing from a model perspective and thinking about the base level of decline on the asset?

On SACROC and, again, this is early, we are seeing the best of both worlds here. We are actually seeing the ability to increase production with less CapEx intensive programs. So that's a bit of a change from where we even more I'd say six months ago, Jesse, and so there's been some improvement there. We just keep figuring out better and better ways to get at the oil there.

When it comes to the other fields, again, I think it is less about looking at it field by field than it is more about the type of development. So where we have existing infrastructure in the field, so we've got gathering lines, we've got injection lines, we've got tanks, those sorts of things. The infill part of our program is going to be economic. And what moves to the margins is a new build out or new development, new pattern in the same development.

That gets a little closer to the edge, and then a brand new kind of greenfield development is probably outside the edge. And that's a real summary way to think about it, and, again, we can get more specific with some specific development plans that we have when we get to the conference next week. But does that cover it, Jesse?

Yes, I think maybe, to look at it, it's the backlog, I think, is the question is heavily weighted toward CO2 development not the EOR business. So I think the push out of the $800 million or so is more focused on our new CO2 source development and not the existing EOR projects. I think that's the way to look at it.

Okay, thanks a lot for the time, guys. Appreciate it.

Adam Steinberg out of Waveny Capital Management.

Good afternoon, Adam.

Hi, thank you. Hi, how are you?

Good.

Good. I will echo the comments that others have made on the call about extending our congratulations to you guys. But it seems like the market is not really rewarding some of these accomplishments that you guys have achieved. And, Rich, I saw your comments in the release today, but I was wondering, maybe you can go further than just saying you won't sell and would the Company consider buying back some of the stock and/or the warrants?

Would the Company consider buying back some of my stock?

Some of the stock in the open market?

No, that's not in our present plans. Again, what we've said is that we are going to concentrate on this tremendous dividend growth story that we've got and be very careful about maintaining our investment grade rating by keeping -- paying close attention to and keeping that debt to EBITDA in the range that we have talked about for the last six months.

Great. And then, just one follow-up maybe, you talked about -- you reiterated the dividend guidance in the future. Does today's acquisition add to that or does it, sort of the core business a little weaker and that makes up for it?

I think this is additive what we are doing today with the accretion in the out years is additive to what we had before. I think you have to look at it on separate tracks. In other words, what we have here is a tremendous set of assets that admittedly are somewhat, I think, pretty minor, in a pretty minor way compared to [if you were peery and peak coming] but impacted by the lower commodity price. We've never denied that, we've given you guidance on that. Any acquisitions that we do, or any new expansion projects that we add to the backlog that we don't have now will, if you want to say, offset that or we will add to it. So I think, we certainly won't do any acquisitions or expansion projects unless they are accretive to the cash flow.

Got it, thanks.

And I am showing no further questions at this time.

Okay. Well, thank you very much, everybody. I know it's been a pretty long conference call. We are very excited both with the results for 2014, the outlook for 2015, and with our newest acquisition. Thank you, and have a good evening.

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