金德摩根 (KMI) 2014 Q3 法說會逐字稿

Welcome to the quarterly earnings conference call.

(Operator Instructions)

Today's conference is also being recorded. If you have any objections you may disconnect.

(Operator Instructions)

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

Okay. Thank you Holly and welcome everybody to our earnings call. As usual we will be making statements within the meaning of the Securities Act of 1933 and the Security and Exchange Act of 1934. I'll make some introductory remarks and then I'm going to turn it over to Steve Kean our President and Chief Operating Officer who will talk about operations and our project backlog.

And then we will go to Kim Dang will take you through the numbers. I want you to treat her respectfully because we just named her as a member of office of the Chairman today. I know you will keep that in mind.

Let me talk about first -- third-quarter performance there's really not a lot to report on the quarter or on our projections for the balance of the year. Steve and Kim will take you through in more detail except that we do now expect to exceed our $1.72 budget target for dividends at KMI and we expect to meet our targets at KMP, KMR and EPB.

Our natural gas pipeline, particularly the interstate portion of our group, are leading the way with strong performance throughout the year. As an indication of the increased demand for transportation on our natural gas pipelines we now have new signed and pending long-term contracts since December of last year, December 13 of 6.4 bcf a day. Now to put that in perspective that's about 9% of the total US gas demand and that number, that 6.4 number is up from 5.3 at the end of the second quarter.

So we continue to make real progress in attaching new throughput agreements to our system. Steve will go into more detail on the operating performance across all of our segments. More significant for the future probably is the size of our backlog of new projects. We went from $17 billion in backlog at the beginning of the quarter to $17.9 billion at the end of the quarter even after deducting about $1.1 billion of projects that were completed and placed in service during the quarter and thus removed from the backlog.

The third quarter additions include some sizable projects that Steve will discuss in detail. To me this growth demonstrates once again the demand for mid-stream energy infrastructure in North America and the size of our backlog together with the enormous footprint of our pipeline and terminal assets is the best predictor of future growth at KM in my judgment.

Now let me also update you on the transaction in which KMI is proposing to buy the outstanding units and shares of KMP, KMR and EPB. We have now received all necessary regulatory approvals except our Registration Statement has not yet been declared effective by the SEC. We expect to announce the date of our shareholders and unit holder meetings in the near future and we're hopeful we will be able to close by Thanksgiving.

To remind you, we expect the resulting consolidated KMI to pay a dividend of $2.00 in 2015 that's an increase of 16% over the $1.72 budget target for 2014. To increase the dividend by 10% a year for 2020 and to generate coverage in excess of $2 billion above these increased dividend payments. And with that I'll turn it over to Steve.

All right. Good afternoon. I'm going to review the business segments focusing on year-over-year performance Q3 of last year to Q3 of this year for each one and the key developments in each segment.

Starting off with gas, very good year. KMP the earnings before DD&A is up $53 million or 9% year-over-year. And we continue to see strong performance at TGP and EPNG as well as the assets that we picked up in the Copano acquisition. Transport volume on the KMP assets is up 10% year-over-year.

At EPB the DCF is up $23 million or 8% year-over-year really due to the drop downs of our interests in Gulf and Ruby that were announced in April of this year. The gas group added on a net basis $100 million to the project backlog, that's after putting into service about $270 million the biggest piece of that was the expansion of our Houston central plant and some associated pipe expansions around that asset for about $250 million.

We had a net add at TGP of about $175 million about the same number at the midstream assets and those were really both associated with LNG markets as well as Mexico. So a net add of $100 million to the backlog and the gas group. We continue to see strong demand for natural gas infrastructure as Rich mentioned. We're seeing it in the shales LNG exports and Mexico.

Our assets are well positioned for all that as evidenced by the 6.4 bcf of sign-up that we've had, so the trends that we been talking about for a long time are now turning themselves into firm transport, long-term firm transport commitments. And that's just mostly the supply side and some LNG and Mexico exports.

That's before we've really seen the demand side of this picture with power conversion in the US and industrial and pet chem on the US Gulf Coast. And to illustrate that point if you look at our backlog you don't see anything in there for those developments yet to come just yet but we can see them over the horizon. If you break our backlog out the gas group call it producer push projects are about $800 million out of the shales.

What I'll call first party LNG which is really the Elba Island and related transportation expansions about $1.6 billion. What I'll call second party LNG which is where we're investing in infrastructure to serve other people's LNG facilities is another $750 million. Mexico was over $900 million in processing and gathering primarily in the Eagle Ford is about $300 million so that's about $4.4 [billion] of the total backlog and you can see we've still got more to come with these other developments.

We still haven't seen the full effect of power and industrial pet chem on the US Gulf Coast. And I think will also see some additional LNG. And all of those things are things that we are well-positioned for.

You would also think with all of this demand side growth and what's happening on the supply side that we're going to see an enhanced value on our storage assets as well. And that is think also still to come. Also a reminder the backlog that we have in the gas group does not get include Northeast Direct or Gulf LNG projects which we continue to actively work. So again, more to come on our well-positioned gas network.

Turning to CO2 earnings before DD&A is up $14 million or 4% year-over-year. On the volume side SACROC is up 12% a huge performer NGLs are also up 7% year-over-year. Yates is down a little bit 3.4%. Katz's volumes are up 27.3% and Goldsmith is basically flat. Overall volumes on a net basis are up 9% year-over-year and really great performance at SACROC with nearly every program that we put in place there for 2014 exceeding our expectations.

The disappointment from a production standpoint is Goldsmith which is essentially flat year-over-year. I would characterize this--the issues here as being less about geology than they are about operations. The oil is there. It's down the wellbore but we've had outages at the wells and outages associated with our pumps there. These are similar but not identical problems that we have solved in other places including SACROC. So we've got a full-court press to turn things around here.

The other even bigger disappointment in the CO2 group is net oil prices taking the Midland Cushing differential into account. That differential alone more than explains CO2's entire shortfall to its plan this year. So very strong volume performance at SACROC and the NGLs, year-over-year upticks at [Caps]. Work to be done at Goldsmith in particular.

Turning to the backlog, it's evenly split now in CO2 between the S&T and EOR parts of our business with about $2.1 billion each. We added disproportionately to the S&T portion of the backlog in the quarter-over-quarter change that we had. Looking ahead we're going to be focusing attention on Goldsmith and we begun hedging and looking at other physical sales strategies that we can use to manage the Midland Cushing spread issue.

On the product side, earnings before DD&A up $20 million or 10% year-over-year. The increase came from year-over-year earnings growth on our less refined product lines. KMCC had a big uptick year-over-year, Southeast terminals in Cochin and those positives more than offset declines at West Coast terminals and Transmix.

Interestingly, refined products volumes year were up 6.8% year-over-year and up 4.1% if you exclude Parkway which we put into service late in Q3 of last year. Contrast that with the EEIA where nationwide the increase in refined products was only 0.8% on a year-over-year basis. Plantation volumes really led the way here as demand to move US Gulf Coast refined products to our markets remains very strong.

In addition to the nice increase we saw in refined products volumes the backlog shows strong demand for additional NGL condensate and crude infrastructure. If you look at the composition of the backlog here, there's a little over $0.5 billion that's associated with UTOPIA and Cochin. Those projects another 550 associated with crude and condensate a KMCC including our splitter project there and another 20 or so one miscellaneous refined products and blending operations. So a good chunk of demand for crude and condensate and NGLs in particular.

The products group also increased their backlog over $100 million while placing into service over $400 million worth of projects during the quarter. The two big ones being Cochin and the completion of a number of KMCC related expansions.

And the big addition being the UTOPIA project moving ethane and ethane propane mix for nova as well as potentially some other customers up to Cochin and then into the Windsor-Sarnia area. We also had another $50 plus million of additions to KMCC related expansion projects. And I have to say overall both in gas and especially in products, the project--the execution on the products in this segment remains very good. They've hit their numbers or better.

With the notable exception schedule-wise of a delay in the first phase of the splitter project in the Houston ship channel. But from a cost standpoint they're hitting their numbers better. And a reminder here too that the backlog does not yet include the Y-Grade project UMTP or Palmetto. We continue to work on those prospects. Palmetto was in the middle of an open season right now until the end of this month. And on a combined basis these projects if they come to fruition would add another $4 billion to the backlog.

Terminals, turning to terminals earnings before DD&A year-over-year up $48 million or 25%. That is the biggest I believe, the biggest ever year-over-year uptick in performance for the Terminals segment. About 70% of that is organic placing a number of projects into service. Versus 30% on the acquisition side. Which is primarily the APT acquisition.

We did experience weakness in our coal export volumes though we do have some protection in our contracts with minimum payments. But we continue to see on the plus side very strong demand for liquids infrastructure and that's evidenced by a net increase to the backlog of about $300 million even while putting $200 million worth of projects into service.

The current backlog is predominately liquids related. It breaks -- [now] there's about $600 million of crude by rail projects that are in the backlog. About $400 million associated with building out the tankers the APT tanker's. Another $1.4 billion that's other liquids, tankage and dock and piping infrastructure and bulk is only about $80 million of our backlog currently.

Looking ahead here we expect to continue to see growth in demand for the liquids infrastructure. I think that demand extends also to our existing assets in Houston and Edmonton where we continue to see nice renewal rates on that but also extends to expansions. On the downside we expect to see continued weakness in coal volumes into next year.

Lastly, Kinder Morgan Canada and the big story here continues to be the trans mountain expansion. You know just a reminder here this is fully under contract. We have NEB approval of the commercial and economic terms of those contracts. Our development costs are almost entirely covered on this project and we do have good cost protection on the most difficult parts of the build.

Last quarter when we had this call we had just received word of a six-month three-week delay in the deadline for an NEB decision so they moved from July 2015 to January 2016 but at that time we had not yet assessed the full impact of that to the schedule. Other than to note that we would be moving from late 2017 to 2018 in-service date.

We've spent the intervening time assessing the routes alternatives in Burnaby, we've looked at our construction schedule very closely and can tell you that we expect now a Q3 and frankly a late Q3 of 2018 in-service for Trans Mountain now. The main thing that's going on there is a separate proceeding for the NEB to assess the alternative routes between Burnaby Mountain and the dock where our terminal facility is down to the dock.

We are in the middle of that process and in the middle of a dispute with Burnaby over how to assess that. We had to examine our construction schedule closely looking at things like the effect on clearing schedules, fish and wildlife considerations et cetera and that pushed us to a Q3 2018 in-service. Notwithstanding the local disputes we continue to make good progress through the application process and we still expect to get our permit on this project and build this expansion.

So that's the rundown on the business units and the major projects and with that I'll turn it over to Kim for a more detailed look at the numbers.

Thanks Steve, so starting with KMP and the GAAP income statement you can see there today the KMP Bboard declared a distribution per unit of $1.40 that's a $0.05 increase or 4% from the three-month in 2013. As a result we will declare a distribution for the nine months of $4.17 or an increase of 5%. Now you can see on income from continuing operations that we're up 40%. If you want to look at it on a per-share number we're up 78%.

We don't think that these are the right numbers to focus on. Because we don't think it gives you an accurate picture of what's going on at KMP. So if you turn to the second page of numbers you can see that [dcf] per unit for the quarter is $1.31. That compares to the declared distribution of $1.40 so we have about 0.94 times coverage, or about $42 million short of coverage.

As we told you last quarter and we've told you almost every quarter we expect negative coverage in the second and third quarter, positive coverage in the first and fourth and for the year to have positive coverage.

Now in terms of net income per unit when you strip out the certain items, we're at $0.57. I've seen a couple of notes out there that said that we've missed the consensus earnings. Let me point out that even though we don't think earnings is the right thing -- earnings per unit is the right thing to focus on, we do give you a budget every year of earnings per unit. We also provide a distribution of how that number breaks out across the year. If you take our number of $2.57 and multiply it by the percentage you would get $0.57 per unit. So we are right on top of our budget at KMP.

And if you look at the other two companies those which I saw notes we missed the consensus, EPB is $0.01 short of that calculation of our published numbers -- public published budget numbers and KMI is $0.01 above. I can't really comment on where the consensus earnings are coming from but they are obviously not consistent with the budget that we put out which we have been very consistent in achieving over time.

DCF in total for KMP is $607 million up $53 million or 10% in the quarter. So, nice growth in total DCF in the quarter for the nine months $1.861 billion up $252 million or 16%. And so let me reconcile for you the $53 million that we're up for the quarter and the $252 million that we're up for the nine months. If you look at segment earnings before DD&A we're up $141 million or 10%. About 72% of that is coming from two segments, natural gas and terminals.

But we also had nice increases coming out of CO2 and products. Our natural gas is up about $53 million and terminals are up about $48 million. Steve took you through all the reasons for that so I won't reiterate that. But nice growth coming out of the segment.

Then you focus on the expense side of the equation. G&A is actually -- it was an expense of $129 million in the quarter. That's a reduction, so G&A expenses lower than it was in the third quarter 2013 by about $8 million and that's a result of higher capitalized overhead as a result of our capital expansion program.

Interest was an expense of $238 million in the quarter. That's about an increase of $17 million over the third quarter of 2013 and that is the result of higher average balances as a result of acquisitions and expansion capital, slightly offset by some lower rate.

Then sustaining CapEx was an increase of $29 million in the third quarter of this year versus the third quarter of 2013. That's within about 2% of our budget. It's actually about $3 million higher than our budget but as I'll tell you in a minute year-to-date we are slightly behind our budget so it's largely timing.

So if you take the segments up $141 million, G&A is a positive $8 million, interest expense negative $17 million, sustaining CapEx $29 million, the GP incentive is up $37 million as a result of higher distributions per unit and more units outstanding and then we have some other items that are a negative $13 million and that's largely just in our calculation in DCF we make some adjustments for things that are not cash that are in earnings and so $13 million there and that gets you to the $53 million.

If you look at the nine months the $252 million our segments are up $575 million or 14%. 83% of that growth again is coming out of natural gas and terminals with gas being up $355 million, terminals being up $125 million. We also saw nice growth coming out of CO2 and products.

On the expense side of the equation G& A is an increased expense versus the nine months last year of about $20 million. Interest is up about $74 million again higher balance slightly offset by lower rate. The sustaining CapEx is up $82 million but year-to-date we're about $23 million lower than our plan on sustaining CapEx.

So we budgeted for sustaining CapEx to increase but some of that is timing actually for the year we're going to be about $16 million positive to our plan. Some of that, about half of that, is just a reclassification to OpEx, so OpEx is higher than we would have expected, sustaining CapEx is a little lower than we would've expected. That explains about a half of the $16 million variance.

But back to the nine months, $82 million in increased sustaining CapEx. The GP incentive up $137 million. For the same reasons higher distribution per units, higher units outstanding and then other items of about $10 million gets you to the $252 million. So versus our budget where we currently expect to end up the year, we currently expect to end up on budget in terms of DCF and DCF per unit.

And let me give you a little more insight into that. The segments are going to be very, very close on a percentage basis. On an absolute dollar basis they are going to be slightly below and that's a result of nice increases in gas versus our budget primarily as a result of new contracts and increased transport revenue on TGP and EPNG. It's a result of contributions from in terminals in the APT acquisition.

And then these positives are more than offset by negative impact of the Midland Cushing differential as Steve mentioned. Weaker coal volumes than we would have expected. Some project delays and lower condensate volumes. The slightly below on the absolute dollars from the segment is being offset by positive variances on G&A interest GP incentive and sustaining CapEx to leave us on budget overall for the year.

Now in terms of KMP's balance sheet we ended the quarter at $21.5 billion in debt. That results in a debt-to- EBITDA of about 3.8 times. That increased in the quarter $817 million and it increased almost $2 billion, $1.99 billion for the nine months. So I'll take you through the change in debt, the drivers of the change in debt.

On the quarter we spent about $1.16 billion in terms of acquisitions, expansion CapEx and contributions to equity investments. We raised about $328 million in equity and then we had a contract buyout that was about $200 million positive. And that was the main certain item back on the income statement was the benefit the earnings benefit of that buyout but we also received cash for that. And then we had working capital and other items that were a use of capital of about $181 million.

Now let me say there are tons of moving parts under here given the size of company that we are but they net out and so what you're left with is primarily a use of working capital associated with accrued interest because we make our interest payments on our debt primarily in the first quarter and the third quarter. Accrued interest was a use of working capital of about $186 million in the quarter.

Year-to-date $1.99 billion increase on the debt balance. We spent about $3.7 billion in terms of acquisitions, expansions CapEx's and contribution to equity investments. We had $1.1 billion of acquisitions with the largest one being the APT acquisition of $961 million that we did in the first quarter. Expansion CapEx was $2.3 billion and then we had about $300 million of contributions to equity investments.

We raised $1.7 billion in equity. We had a little under a $200 million receipt of cash from the contract buy out and then we had a use of working capital and other items of $178 million. Again, a lot of moving pieces but the primary use of working capital was accrued interest. So that's it for KMP.

Looking at EPB, EPB for the quarter is declaring a distribution of $0.65. That is flat with the third quarter of 2013. That results in a declared distribution of $1.95 for the nine months which is a 3% increase versus the nine months of 2013. When you look at EPB's DCF in the quarter, it's DCF was $0.65 versus the declared distribution of $0.65 so right at one times coverage. The DCF per unit is up 12% versus the third quarter of last year so very nice growth in DCF per unit.

Year-to-date DCF per unit is $2.02 versus a distribution of $1.95 and so about $15 million of positive coverage for the nine months on EPB. The $2.02 is up about 3% from the nine months in 2013. DCF in total $150 million was up $23 million or 18% for the three months. For the nine months $454 million, up $29 million or 7%.

Let me reconcile for you the $23 million increase in DCF for the quarter and the $29 million increase in DCF for the nine months. The top line of the page you can see earnings before DD&A of $3 million. That generally is where you expect to see the increase in cash coming from our assets but because the drop downs that we did for both joint ventures, as you know, we adjust our DCF calculation to add back JV DD&A and subtract out our share of sustaining CapEx. And the reason we do that is to more closely reflect the cash distributions that we receive from these investments.

So if you add back the JV DD&A, the change in JV DD&A from the quarter in 2013 to the third quarter of 2014 that's $31 million increase. And then we have a $3 million adjustment down in our DCF calculation to adjust out some of the non-cash items, primarily deferred revenues [and AFUDC] that's about a $3 million negative in the quarter. So really the assets contribution is up about $31 million.

The May drop down contributed about $46 million and then we have some degradation in [SNG] and [Wick] associated with the rate cases and also Wick associated with lower rates on contract renewals. On the expense side of the equation G&A interest-sustaining CapEx, G&A is actually down $1 million versus the third quarter of 2013.

Interest is up, so increased expense about $3 million associated with interest expense from financing the drops, sustaining CapEx is up about $3 million and that gets you to about $26 million of improved cash flow. The GP incentive is up $3 million because the more units outstanding that gets you to $23 million increase in DCF in the quarter. Year-to-date the $29 million earnings before DD&A again up $6 million.

Similar story here, you also have to add back the change in the JV DD&A about $52 million and then take out some of the items that we adjust that are non-cash to get the DCF which is a negative $9 million, that gets you to about $49 million increase coming from the assets. A drop of about $77 million benefit in the quarter and then again in the year-to-date and then again similar story on Wick and SNG, down versus the nine months of 2013 on the rate cases and on the case of Wick, the lower contract renewals.

If you look at G&A interest and sustaining CapEx the change in those is about $2 million increase in total combined for the nine months, take that off of the $49 million from the assets that gets you a $47 million increase. The GP incentive was up about $18 million on more units and a higher distribution to get you to the $29 million.

EPB is having a good year. EPB we expect to meet our budget right now. On a DCF running slightly ahead of our budget and that's coming from basically a little bit better performance across the board. Better performance from the assets, a little bit lower G&A, lower interest and lower sustaining CapEx.

Looking at EPB's balance sheet, EPB totals ended the quarter with total debt of $3.642 billion. That is a debt to EBITDA of about four times and so up from the end of the year but consistent with EPB's budget. The change in debt in the quarter is a reduction of $99 million. For the year it's an increase of $464 million. In the quarter we spent about $23 million in terms of expansion CapEx and contributions to equity investments.

We issued about $76 million in equity and the working capital and other items were source of cash of $46 million which is primarily accrued interest and accrued taxes. Year-to-date acquisitions, expansion CapEx and contributions to equity investments was a use of cash of $1.028 billion with the biggest component of that being the $972 million for the drop down. We issued a little under $500 million of equity, $498 million and then we have a little over -- $66 million source of working capital and other same factors is on the quarter primarily accrued interest and accrued taxes.

Returning to KMI, KMI we are declaring -- the Board declared a dividend today of $0.44 per share. That is a little bit better, that is $0.01 above where we would have expected to be for the third quarter and that is why you see our guidance that we expect to exceed our $1.72 budget. That result in a declared distribution for the nine months of $1.29 which is an 8% increase over the nine months in 2013.

The $0.44 compares to cash available of $0.42 so we're slightly negative on coverage as we would have expected similar to KMP and as we tell you almost every quarter we expect negative coverage in the second and third quarter, positive coverage in the first and fourth and to be approximately one time for the full year. For the nine months the cash available of $1.29 is equivalent to the declared distribution of $1.29 so right at one times coverage.

Cash available to pay dividends $435 million in the quarter, up $11 million or 3% for the nine months. $1.34 billion up $109 million or 9%. So let me reconcile the $11 million increase in the quarter and the $109 million increase for the nine months. In the quarter the cash coming from KMI's investments in the MLPs, so from its GP and LP interest was up $48 million or 8%. The cash generated from other assets was down $47 million as a result of the drop downs.

And then the combination of interest G&A and taxes was a benefit of about $10 million meaning we had less expense in the third quarter of this year than we did in the third quarter of last year. And that leaves you up about $11 million.

On the nine months the cash coming from the MLPs up $182 million or 10%. The cash generated from other assets down $76 million. Again, this is a function of dropping down assets to EPB and KMP.

And then interest G&A and taxes the expense items our benefit of $3 million. That's lower G&A and interest more than offsetting higher taxes leaving you up $109 million in the quarter. Versus our budget we are ahead -- slightly ahead of our budget in terms of cash available to pay dividends and as we have said we expect to exceed the dividends per share of $1.72.

Looking at KMI's balance sheet we ended the quarter at $9.3 billion in debt. If you look at the fully consolidated number of $35.5 billion. That is 4.9 times on a fully consolidated basis debt to last 12 months EBITDA. And we are on target when we close transaction to be at about 5.6 times as we laid out under the investor presentation. The change in debt in the quarter is up $54 million. It's down a little under $500 million, $493 million year-to-date.

The $54 million we posted margin of about $60 million and then we had a whole host of other items that comprise the difference to get you to $54 million increase in debt. Those include the fact that KMR that we include in the metric is cash. We did not choose to sell those shares and so that's a $23 million use of cash. We have a $63 million benefit from the fact that we actually paid lower cash taxes [of] what's in the metric because we straight-lined, if you will, the NOL that we got in the El Paso acquisition versus on a true cash tax, for purposes of the metric, versus on a true cash tax basis we're using that up as quickly as we can.

We had about $18 million in one-time items, primarily the legacy El Paso environmental and marketing and then we had some transaction costs associated with putting the bridge in place and with the SEC filings and banking fees. For the year-to-date $493 million, we received $875 million in drop down proceeds. Year-to-date we repurchased 192 million between warrants and shares. We had about a 60 million margin call.

This is where we posted cash instead of LCs because there was a benefit, it was cheaper to post the cash and so we converted it from an LC to cash. We made a pension contribution of $50 million and then we add about $83 million in working capital and other items, to again, KMR about $69 million and the difference between the cash taxes on the metric was $189 million.

Of course the one-time items were $89 million use on distributions we receive and dividends we paid about $72 million use and then we had about $39 million in terms of transaction costs that issue cost associated with refinancing our revolver earlier in the year and then the financing on the bridge and the revolver with the transaction. So with that, I'm done.

Thank you Kim and I might add that this will get a lot simpler hopefully by the next time we talk because we will be one company instead of three. And with that Holly, we will open the floor for questions.

Thank you Sir.

(Operator Instructions)

Carl Kirst, BMO Hi Carl, how are you doing?

Hi thanks, good Rich. Couple questions if I could on the backlog? And the first really is to maybe just get a little bit more of a refined cents of UMTP, I guess the shipper paying sort of ended at the end of August to the extent that, that's still in negotiation.

Is that something you are looking to just negotiate through this winter to see how NGL basis does and whether you might get more people to sign on at that point? How long do you let it go before you start looking at a Tennessee gas back haul project again?

Okay, I think we continue to pursue this project because we continue to see very strong interest in it. Each period that we go out to survey the field and survey the market it seems like we generate more interest from the period prior but we haven't been able to turn that into credit -- sufficient credit worthy counter-party commitments to carry the project through and allow us to put it on the backlog and actively pursue its development.

Well, we are actively pursuing its development. So kind of the reset we have done Carl, is to say, what does the market really need out there? We think the market really needs a 2018 in-service date. There's been a lot of talk for awhile about 2017. But there doesn't seem to be much harm in a 2018 in-service date and so we've adjusted our spend, our development work. That moves us to a 2018 in-service but allows us to continue the development of the project at a lower cost as we pursue abandonment on the Tennessee Gas pipeline system.

I think the short answer is still looks like a very viable project. We're still working it very hard. We found a way to continue to develop the project as the market matures into it and that's what we expect to happen. We do, as you pointed out, always have the option of going to a southbound Tennessee haul.

It's not a large amount of capacity that this line represents and so I think it's a much more attractive opportunity for us as a company to pursue the Y-Grade line and so we'll continue to do that until it's apparent that there's not going to be sufficient commitments coming forward. We think it's the best long-term, most efficient solution for the customers up there and we're counting on them realizing it at some point here.

Great and I appreciate the color and maybe one other question? Looking at New England [NED] obviously a very big potential project. Correct me if I'm wrong, my recollection is that at least on the market piece the [LBC]s have signed up for roughly a half BCF a day, and you all were just in filing for Maine and I guess depending on if they bite that might be something that could potentially push you over the commercial transom.

And my question is, how long do you think that process takes for the state of Maine to evaluate that situation? Is this a first quarter, second quarter 2015, just any kind of zip code you might have?

Well Karl this is Rich. It's complicated a bit by the fact that the Chairman is leaving at the end of the year. That said there seems to be a great deal of interest by the state of Maine in pursuing this project. And we're working with them and pushing them to get a decision just as quickly as we can.

We're working there toward critical mass, we haven't put it in the backlog yet and won't until we get that critical mass. We're working with a number of customers for additional capacity and the project again looks to certainly something that's needed for New England and we're also looking very seriously at our ability to reroute certain parts of that to obviate some of the uproar we've had in the Berkshires about where our pipeline is running.

We think we found solutions to route the great bulk of it along right of way which would not be as disturbing as the original plan was. We think the original plan took into account the needs and issues with the potential neighbors but we're going back to the drawing board and bid on that and we'll be looking -- we haven't filed the final route yet, we'll be looking to do that as we move forward.

So that's a project that again we continue to move forward on. But we obviously have to see the critical mass before we put that in the backlog and announce is a definite go project.

Understood. Those are my questions and I meant to pass on my congrats to Kim so I'll do that now.

Thank you Karl.

Ted Durbin, Goldman Sachs

Hello Ted, how are you? Hello Rich I'm doing well, thanks. Maybe just start with the moving oil prices here and can you give us an update here on where your hedge percentages are as we look out for the next 1 year to 3 years and maybe also sensitivity analysis on (inaudible) moving oil prices how that impact DCF for 2015.

So for 2015 right now we have about 64% hedge at a price of $90.53, 2016 we're 46% hedge a price of $85.86, for 2017 we're 33% hedge at a price of $83.14, and for 2017 we're 17% hedge at $83.80. By the time we get to the end of this year the beginning of next year, we would expect to be about 80% hedge on 2015. Which would leave our sensitivity somewhere to what it has been in prior years of about $7 million in DCF per $1.00 change in a barrel of oil.

Great. That's very helpful. Thanks. Next question is just -- from a shareholder vote here, maybe it feels like it's been delayed a little bit more than what we had thought it was going to would be, anything there? And then as you talk to the KMP unit holders in particular where is your level of confidence in terms of getting that majority vote you need?

Let me say first of all it's not delay. We'd be -- we said sometime late in the fourth quarter we would be happy if we can -- certainly hopeful we're moving it forward to get it (inaudible) by Thanksgiving. I'm going to turn to David Michels. David do you want to take them through the analysis of KMP unit holders?

The way to remind you the way that the (inaudible) KMR voters shareholders will be able to direct their [i-units] to vote in the KMP unit holders votes so that represents about 28% of the total KMP unit quarter base and if you break it down and use some reasonable estimates on how institutional KMR holders will vote and how KMR retail holders will vote, we think that, that will represent about 22% of KMP's votes.

If you at on top of that KMP insider votes and KMI's ownership of KMP, that gets you to about 30% of the total votes that we (inaudible) reasonably assured to vote for the transaction. That would leave us with about 97 million units needed to get us to the 51% level and that's 97 million units out of about 300 million units remaining outside of those contingencies that we just walked through.

We think -- and of the 297 million that remain that we need 97 million out of 90 million of those our institutional holders and we think that those are going to turn out overwhelmingly in favor of the transaction. We feel pretty comfortable that we're going to be able to get there but we're not taking it for granted we're going through a very thorough proxy solicitation process once the (inaudible) is deemed effective.

Very, very helpful. Thank you for the detail and if I can get one more in? Obviously, you had a big fall off in the market here including some of the midstream assets. I'm just wondering if you are seeing even better opportunities potentially out there now given some of the asset values maybe a little lower than they were before?

I think in the long run if that there's a potential for it to be beneficial in exactly that way but it's certainly too early to predict. You need to see where this thing settles out and of course you know the midstream sector rallied pretty nicely this afternoon. KMI was up about I guess close to 3% or 2.5%. As were a number of other energies. We'll just have to see where it is but certainly I think in the long run the outcome of this will be asset values might change a bit that would give an opportunity for a company like Kinder Morgan to make more acquisitions.

Okay. Thank you very much. I'll leave it at that.

Thank you Ted.

[Schner Kersherney], UBS.

Good afternoon.

Hi, good afternoon everyone and congratulations Kim. I was just wondering if you could take a step back from specifically talking about [micro] issues with KMI? As [Ted] just mentioned the markets been challenging the last few weeks, we've had this big decline in oil and we've seen these steep declines in the past.

I was wondering if you could sort of walk us through the discussion process that you have with producers before you start an open season process? Talk us through maybe how they think about short-term pricing trends versus long-term pricing trends as they establish their CapEx and how they come to you in terms of how you provide solutions in terms of resolving bottlenecks and so forth and how we should be thinking about CapEx given the short-term volatility that we've seen?

First of all, of course we're talking about a broad range of projects here ranging from CO2 supply contracts on the one hand to natural gas and products pipeline projects on the other. With regard to most of our midstream pipeline issues we don't see much change as a result of lower prices in fact you could make an concurrent argument that a lower deck of prices on crude and NGLs will have a positive effect on people ramping up Petro chemical usage in the months and years to come.

So I don't think that's a negative on our ability to as you put it, get around these bottlenecks and resolve issues. And clearly, so much of it now as Steve pointed out is returning to demand pull for this. The LNG users the petrochemical users and other demand -- other users from the demand side.

Now I think it's a different issue on the CO2 side and there we've looked very carefully at what we think are sort of clearing prices and this is going to vary widely with who the producer is and what means they have. Let me start by saying that we have [floors] on the great bulk of our contracts so while there is some movement up and down with the oil and that's part of the $7 million per dollar that Kim was referring to we do have floors across the board on that.

If you then look at what does it really take in the Permian Basin to want to drill, we think from the standpoint of a flood that's already going, just incremental CO2 to expand the flood it's probably in the $40.00 to $45.00 range. We think for instituting a new flood in the Permian basin and this is based on our own experience at SACROC we think it's probably closer to $60.00. Let me say again, that's going to vary with the acreage. That's going to vary with the producer.

But what it says to us is that CO2 floods are certainly economic at prices well below where the current price of oil is. And so that's I think certainly something that we will watch very carefully on a going-forward basis both on the S&T side of our CO2 operation and obviously on the OR side. But so far this is not a big issue for us in terms of moving forward with our projects in our view at this time.

Okay thank you Rich for that perspective. Just two quick follow-up questions. You talked [around] the conversion of your shadow backlog to backlog in your prepared remarks. I was wondering if you could sort of give us a sense of where the shadow backlogs (inaudible) will incremental projects add to the shadow backlog (inaudible) the cost?

Steve?

If you look at the projects that I mentioned as I went through each of the business units and just added all those up on a [eight-eight] basis that's about $15 billion to $17 billion when you take the ranges into account and that included Palmetto, the Y-Grade line, NED, one other one, Gulf LNG. So that's a substantial part of that. Some of this will have overlap but in the gas group we have an $18 billion shadow backlog that will double up on NED and Gulf LNG in that respect.

There are a lot of projects out there that we are pursuing and they have some reasonable probability associated with them it's just that they're not high enough probability for us to call them near sure things. But that's order of magnitude and we continue -- those are some of the big ones. The four that I called are some of the big ones and there's a lot of smaller projects in the terminals sectors, things in CO2 that we're looking at.

Products pipelines it continues to be a number of projects for build out there. So again, I think the environment is very good for us. I think we're very close to turning a couple more of those into on the backlog moving them from one to the other. But just didn't quite get there this quarter but I think may make some progress in the coming quarter.

And one last final question if I may? You sort of talked about contract renewals at the beginning on gas line. Have you seen any trends towards producers willing to take longer term contract renewals versus what they typically would do on a renewal? Is there any lengthening that's going on as well as from how you think about a pricing perspective?

I will turn to Tom Martin for that.

We definitely are. I think you have to look at it on a regional basis but clearly the activity that we're seeing out west on the EPNG we're seeing both producers and end-users stepping into longer-term agreements on existing capacity and also sponsoring expansion projects. Certainly Tennessee Gas we're seeing much of that driver to this point being producer orientated both on existing capacity and on expansion capacity.

But I think really -- not to say that, that's part of the expansion and growth we've seen is ending but we're certainly seeing a shift towards more on the market side now going forward than what we had seen over say the last year, to year and a half, and I think evidenced by really the last two quarters of [all] projects be sponsored predominately more on the market side being LNG as well as Mexico exports and I think we'll start to see power and industrial expansion related projects in the coming quarter.

And sort of symbolic of that is what we announced yesterday afternoon. We have two new projects on the gas group side, 500-a-day going to, I still want to call it MGI, it's MexGas now, long-term contract and that's on top of in excess of 500-a-day that we signed up several months ago.

So that's a little over 1 billion-a-day going into Mexico on long-term contract just across our system and then we also announced yesterday associated with that on that Lone Star project another 300-a-day which we have an end-user signed up for that capacity and in fact that may even be enlarged as we go through the open season but what we announced yesterday was just that we would proceed with the 300.

We have enough to make it a valid project. So that's the kind of end-user demand we're seeing, it's definitely linked in with the terms. I think we're even seen people as capacity comes up and open on a bid situation where they have a [roper] they now have to bid longer-term in order to protect that capacity. People are seeing I think, that this capacity in general is only going to get more valuable as time goes on as all these demand side projects come online.

Great. Thank you very much for that perspective. (Inaudible) have a great day.

Mark Reichman, Simmons & Company

Hi Mark, how are you?

Good. Thank you. With respect to the announced expansions that Pasadena and Galena Park I was wondering how you think about export opportunities in general whether it be LPG's refined products and even process condensate? As you survey existing storage and loading capacity where do you think opportunities remain unfulfilled and also in light of a number of international refinery additions that are designed to yield ultra low sulfur diesel for export how deep is the market do you think to accept drilling refined product exports from the US?

We're right in the middle of all of that and what we announced yesterday certainly involves that area. Steve?

So what we announced yesterday is significant tank expansion underwritten with some newly executed contracts from one shipper in particular and we have some previously executed contracts and also includes an expansion of a ship dock to get at exactly what you are talking about. I'm not sure I can give you better numbers than what you can read other places in terms of what the demand is going to be for additional export capacity but what I can tell you is that we're seeing people increasingly interested in capacity that they can get to a dock line.

And we have perhaps the biggest refined products storage position on the Houston Ship Channel and the combination of our Pasadena and Galena Park facilities and with some expansion at BOSTCO as well and we are expanding ship docks and we're expanding barge docks throughout that complex, so there is a lot of demand for that. We've got on a smaller scale a project that we're looking at our Fairless Hills terminals in the Philadelphia area that would involve LPG export.

And I think those are the two big locations that you will see the demand. You are going to see it in the Houston Ship Channel we've had all the refined product capacity and a little bit on the Northeast where people are looking for ways to get the liquids product out of the Marcellus and Utica to overseas markets.

What that aggregate number turns out to be I don't know but we didn't used to charge for, or be able to charge for access to our docks and now we're charging for access to our docks. I mean it is an extremely valuable bridge between the interior United States and the world market for refined products. So, demand is going up, how are up it goes, who knows? We base our judgements on what shippers are willing to commit to and we're seeing an uptick in those commitments.

And I think right now, frankly I haven't updated these numbers this quarter, but I think we believe we are handling something between one quarter and one third of all the refined products exported across the Houston and Beaumont area. And then, I think it's also instructive that this storage is so important and growing so dramatically and to put some numbers to that.

I believe with this project that we announced yesterday on the terminals, I think that will when completed, that will take the Galena Park project the combined Pasadena Colina Park project to over 30 million barrels of storage and if you add up everything we have on the Houston Ship Channel I think that when that's completed we'll be slightly over 40 million barrels of storage.

So that's a really tremendous position to be in when you have the kind of need for export, the need for avoiding volatility in pricing. We think this storage is going to become more and more valuable and we're seeing that in the market.

Thank you very much.

Darren Horowitz, Raymond James & Associates

Hi Darren, how are you?

Hi, fine, thanks Rich, hope you're doing well and Kim congratulations to appointment to the office of the Chairman. Just a couple quick questions. The first, on TGP, what I'm thinking about broad run and the associated expansions you layout post [enteros] anchor commitment, if I start thinking about Rose Lake in Connecticut and the other initiatives that you're working, is it fair to assume there's going to be at least one bcf, if not 1.2 BCF a day that could be hitting that West Virginia receipt point and moving down to those delivery points in Mississippi and Louisiana? Because in looking at basis, specifically [Techarm 2] and Dominion South (inaudible) it would look like that's probably one of the biggest areas for you guys to invest in [chrono] capital?

I think we're certainly taking a look at what our next big project would be. I think it really boils down to what is the clearing price in the market for incremental expansion but I think there's more volume that wants to move southbound. We are seeing some customer interest in diversifying some into Canada and so, one other project announced yesterday into Chicago, so I think customers are looking at a portfolio of growth.

As I've said in other quarters I think from our perspective we're needing a market [claim] price north of $1.00 to do incremental projects with (inaudible) at least initial feedback we're getting at this point is it's probably still a little bit on the high side.

Okay. And then Rich, if I could go back to an earlier comment that you made regarding the Northeast energy direct project and rerouting that or moving along the existing rights-of-way. Is that the variance between the original cost estimate that you outlined of $6 billion and the new forecast of $4.5 billion to $5 billion? Or, has there been any change to the scale of the scope of either Phase I or the second phase initiative into Massachusetts?

No, there really hasn't. We've just refined the cost and got it to a more likely area of what we think the spend would actually be and the $4.5 billion to $5 billion is the result of that kind of pinning down where we think the real construction will come out. Actually, the rerouting would be an increased cost as part of that, something in that same range but would be a net increase because they're having a few more miles of pipe.

But on the other hand we would avoid most of the section 97 land in Massachusetts and just would be largely along utility right-of-way. But we're still looking at that and we're in the midst of doing that.

Okay and last question for me Steve. Regarding CO2, if you could, could you quantify what that current middle in the Cushing differential could have an annual cash flow if it stayed at this level? I'm just trying to get an idea for the sensitivity for every dollar per barrel move in that spread.

I don't really have a sensitivity for you for that. We are -- I can tell you that we been actively putting hedges on for 2015 at levels that are, call it $4.00 better than what you're seeing in the current market right now.

Okay. Thank you very much. I appreciate it.

Thank you Darren.

Craig Shere, Tuohy Brothers

Thanks.

Hi, how are you doing?

Very good. Thanks Rich and congrats Kim. A couple quick ones here. Does the $2 billion effective quarterly increase in your gross backlog favorably impact, I believe you are just over 9% combined enterprise EBITDA a five-year CAGR, if your 20/20 that was noted in your S-1? I'm just trying to see what was baked in that? And where do we start getting incremental?

Kim?

No. I think that, that backlog is -- we actually have, still have, some un-identified in that five-year plan. Obviously, this eats away at that but it's not going to be incremental at this point to a 9% growth.

Okay. Once we start getting through the backlog that was included in that guidance if you guys can give us a heads up that anything new is incremental, that would be great.

[Certainly].

We will do that.

And can you provide some more color around the continued growth in SACROC? You kind of referred to it but not in much detail and also the Yates NGL flooding concept and the latest draws updates?

I'll turn it over to Jim Weurth who runs our CO2 operation.

SACROC, I guess three main areas we've had real good success with the horizontal wells that we're using as injectors of CO2. We're getting good response from those so the bypass wells that we've talked about in the past, looks like that going to be a real good outcome for SACROC. So that's one.

Two, with the seismic we had, initially I think we'd said we'd had about five or six pinch out wells that we've been able to identify in fields and drill, we've built 22 of those now. I think those are running about 1,100 barrels a day higher than we anticipated. We have several more of those identified as the seismic processing continues to give way. The other area I think, conventional in fields, we've dug a couple of those and been very encouraged with that and one of them starting out close to 700 barrels a day back earlier in the year, still producing 400 barrels a day.

The second one coming out at over 400 barrels a day so a lot of opportunities there. We continue to look at fringe areas. We know we have a few more programs out there out in the flat (inaudible) there and around some of the fringes around both the east and west side of SACROC. So continued opportunities at SACROC that we are finding there and I think we'll see -- continue to find more as we go forward.

At Yates, on the hydrocarbon [municipal] the good and the bad news there is we thought we'd have a test of putting some NGLs down into the gas cap in the third quarter. The problem we had is we needed a baseline and we got the first well we picked the first oil there, we're currently still producing about 350 barrels a day on it. With that has done is its open up another opportunity for us to look at this [purged] oil and we're doing that.

We're taking some wells in there and actually [perping] and picking up some of this purged oil and it gives us a great opportunity there. I think now we have identified a couple of wells where the wellbore integrity is real good. We think we get the baseline fairly quickly. We hope to do the injection of the NGL's at fourth quarter.

Well hopefully we'll see some results (multiple speakers).

We hope to continue on the [Ros] we have hundreds of wells drilled at this point in time, facilities are going in, we would still expect bringing the actual injection a little bit forward. We're hoping to start injecting by November 15. We'd have all our production facilities up and running to go by late December. Be able to handle any gas or fluids that come out the other side. So we would expect to see some results on those by the end of first-quarter 2015.

Okay. And the final results are yay or nay on the NGL flooding, is that a first-half event?

We have not even -- on the NGL flooding, we have not even had a chance to flood it yet, that's why I said that'll be fourth-quarter initiative.

Okay. Thanks a lot.

John Edwards, Credit Suisse

Hey John, how are you doing?

Good afternoon Rich. Doing well. I also want to say congrats to Kim as well. Maybe I missed it, but what's your range of total shadow backlog right now?

I think Steve said, and you get into a shadow backlog John it's very difficult to identify, but I think the number he said was $15 billion to $17 billion.

Yes, that was just the projects that I mentioned. A different way of looking at it is, if you look at the gas group alone, it's $18 billion dollars. I don't think we've calculated or identified a specific one for each of the other business units though John. It's got to be $20 billion plus but we haven't articulated that.

Okay. So the $18 billion is in the gas group alone but the $15 billion to $17 billion?

That included some of the gas projects John. If you wanted to look at $18 billion in gas and look at the non-gas projects that would be another $1.1 billion or so, 88s on the Palmetto project and then the Y-Grade project, call it a little over $3 billion and again, those are 88's, don't take into account if we ended up, we don't have one today, but if we ended up with JV partners on those.

So that's another $4 billion plus on top of Tom's $18 billion and that's just in the products group and we have not gone out and calculated and compiled a shadow backlog for terminals for example or even fully done one for products. We kind of summed it up, the prospects are very good and we'll go knock these things down when they get in front of us and go from there.

So if I add that up, I could characterize it in round numbers something like, call it $20 billion to $24 billion of shadow?

I would say north of $20 billion. I don't know how far north.

Okay. That kind of helps us think about that. And then so you sort of answered this earlier so, in light of all the volatility in the market you're not really seeing anybody -- you're not really seeing this impact your discussion on potential projects or impact interest in terms of future going forward? You're not really seeing any delays or deferrals or anything like that given the market volatility?

We are not seeing that thus far.

And to Rich's point earlier, it doesn't mean that you won't see some of that of the producers side, some harder hit producers maybe, but lower prices are going to be very bullish for the demand side which is where we still have yet to see the full needs come to market to sign up for the firm transport and storage commitments that they're going to need to survey.

Okay. That's very helpful. And then so and as far as when you consolidate close and everything the guidance you've put out there is basically 16% dividend growth. In 2015, 10% thereafter and I think you premise that on roughly $3.5 billion spend per year so assuming some of these shadow projects become a reality, effectively you're saying there's potentially upside to those numbers. Is that a fair characterization?

The $3.6 billion per year did not include Trans Mountain. You have to add that on to it to get to your total.

But I think you can see from all these projects John that's why we're comfortable with thinking that, that level of capital expenditures is pretty consistent with what we've been doing. It's certainly obtainable and if anything as I said at the beginning, our [larger] seems the opportunities with midstream infrastructure are better and they keep getting better. I think Steve and Tom and I have all said we can't predict the future, there may be some impact particularly some of the smaller producers. We have not seen that yet.

But certainly we think the demand is going to be the big driver in the future and that may actually improve as a result of lower prices if indeed the prices stay lower. That's certainly what we saw on the natural gas side.

Okay. And then just lastly and you are still thinking sort of 5 to 5.5 times leverage for the [consolidate] entity at least through 2020 or so that's still the plan?

Yes.

Okay. That's all I have. Thank you very much.

Thank you John.

Becca Followill, US Capital Advisors

Hi Becca, how are you?

I'm good thank you. Better this afternoon that I have been the last couple of days. Can you talk about, back on Trans Mountain, the Burnaby issues and the latest route to tunnel under the mountain and the delays. Does it have any impact on the cost estimate at this point?

Ian Anderson, president of Kinder Morgan Canada, (inaudible). No, Becca it's not going to have material cost impact on the overall project whatsoever. A little more spending upfront to do the assessment of the geology of the mountain but not significant.

Great. Thank you and then there's been an amazing number of new pipelining options just in the last six months. And when we look at the last build out cycle we had in 2008 or 2009 there was a lot of cost overruns. How are you guys planning differently in the cycle given what we went through in the last time and the number of announcements?

Now, that's a very good question Becca. I think first of all we're looking very, very carefully at our costs in terms of escalation both of materials but more importantly, putting into our estimate adequate cost escalation on the labor side. I think that's extremely important. If you look across our business units right now on all the projects we're working on and Steve kind of alluded to this, actually products on all the projects that they're working on is actually running about 1.5% below the original estimates.

Natural gas is right on. CO2 is right on. And the only place we've had overruns is on terminals primarily some of our Canada projects. And that's between 6% and 7% overrun. So we have not seen any dramatic issues thus far.

The second thing that's important above just watching and getting your estimates right is trying to get a sharing mechanism with your shippers on some of the more inflation-prone areas for example on Trans Mountain we have some sharing arrangements on construction costs in the lower mainland, this Burnaby would be an example of that. We have some sharing cost on the cost of first Nations involvements.

And that's what we're trying to build in, in various projects. There's nothing perfect here and it's something that I think is going to be a challenge to the industry in the industry is just going to have to watch it very, very carefully.

Can you say what escalators you have built in?

It varies with the project and it's specifically with the geographic location. Obviously you build in higher escalators in geographic areas where you don't have access to as many competitive -- competitors in a particular subcontracting area. So it varies all over the waterfront. But we think we're building an adequate incremental numbers as we go forward.

Thanks and the last question is, just on the SFPP settlement does this finally put to bed all this long-standing litigation?

It does we think. It has to be approved by the CPUC. They fast-tracked it and we expect it will be approved but obviously it has to be approved by the commission. Yes it does and in fact we have a three-year moratorium on rates on the SFPP system on the CPUC portion of it, the [intrastate] portion. So yes, we think that does put it to bed and as we've said in the press release I think we detailed the details of it really.

So we can take 10 pages out of the 10-K then?

I certainly hope so Becca, that's a good catch.

Great, thank you.

Thank you.

Jeremy Tonet, JPMorgan

Hi Jeremy, how are you?

Hi, great and my congratulations to you as well Kim. At the risk of getting ahead of myself a bit, I was just wondering if you could provide us an M&A wish list in terms of what areas of midstream you would like to expand into? I guess the question is, it seems on the NatGas pipeline side I imagine you might run up into antitrust considerations, I'm just wondering what other parts of midstream you might want to extend in more? Just any color that'd you be willing to share would be great.

The color we would be willing to share as we're looking at all realistic opportunities across the spectrum and all of the businesses that we're in.

That makes sense fair enough. Figured I would try. Thanks.

Okay. That looks like that's the last question. Thank you all very much. Have a good evening and we appreciate you spending the last hour and a half with us.

This does conclude the conference.