Kinder Morgan, Inc. (KMI) Q3 2017 Earnings Report, Transcript and Summary

Welcome and thank you for standing by. And welcome to the Quarterly Earnings Conference Call. At this time all participants are in a listen-only mode until the question-and-answer portion of today's call. [Operator Instructions] Today's conference is being recorded. If you have any objections you may disconnect at this time. I will now turn the call over to Mr. Rich Kinder, Executive Chairman of Kinder Morgan. You may begin.

Okay, thank you Brendon. And before we begin as always I'd like to remind you that today’s earnings releases by KMI and KML and this call include forward-looking and financial outlook statements within the meaning of Private Securities Litigation Reform Act of 1995, the Securities and Exchange Act of 1934 and applicable Canadian provincial and territorial securities laws, as well as certain non-GAAP financial measures. Before making any investment decisions, we strongly encourage you to read our full disclosures on forward-looking and financial outlook statements and use of non-GAAP financial measures set forth at the end of KMI’s and KML’s earnings releases and to review our latest filings with the SEC and Canadian Provincial and Territorial Securities Commission for a list of important material assumptions, expectations and risk factors that may cause actual results to differ materially from those anticipated and described in such forward-looking and financial outlook statements. With that behind us, let me start by making just a few remarks. Steve and Kim will detail the financial results. But once again the cash flow of KMI remains strong and demonstrates in my mind the strength and stability of the assets underpinning Kinder Morgan. Now let me remind you that a segue into the fact that generating strong, sustainable and growing cash flow is our prime objective at Kinder Morgan. Until late 2015 after the collapse in oil prices occurred, our strategy was to distribute essentially all of that operating cash flow to our shareholders through dividends and to fund our expansion CapEx by issuing equity and debt in roughly equal increments. That approach worked through thick and thin for about 18 years, but it became prohibitively expensive with the events of the weakened energy markets after the oil collapse and thus in December 2015 we cut our dividend. That's the hardest decision we've ever had to make at our company. We changed our strategy and decided that going forward we would live within our cash flow funding our expansion CapEx and dividends entirely out of that cash flow without needing to access capital markets for debt or equity, except of course the rollover of long-term debt obligations. At the same time we wanted to strengthen our investment grade balance sheet and reduce our debt to EBITDA ratio to around 5x. How we done in the seven quarters since we changed our modus operandi? Well we've paid down approximately $5.9 billion in debt, thereby strengthening our balance sheet and we've paid for a fairly robust expansion CapEx program and all our dividends out of our cash flow. As a consequence we announced on last quarter's call our future dividend policy, which calls for increasing the annual dividend from our current $0.50 to $0.80 in 2018 that's an increase of 60% and with further increases of 25% per year in 2019 and 2020, which results in a $1 dividend in 2019 and $1.25 in 2020. In addition, our board authorized $2 billion in share repurchases during that three-year period. And we intend to continue to fund all expansion CapEx needs out of our cash flow. I remind you that Trans Mountain of course is being funded and our publicly traded Canadian affiliate, KML, without further KMI capital infusion. As the largest shareholder in this company I believe that this is a reasonable and sustainable path forward for this company. And I just want to reiterate those points for your benefit and I’ll turn it over to Steve.

Alright, thank you Rich. I’m going to update you on KMI performance and then turn it over to Kim as usual to take you through the financials. Following that I'll update you on KML and turn it over to Dax Sanders, CFO of KML, to give you the KML financial and capital raising update. Then we’ll take your questions on both KMI and KML. Starting with KMI, we had a good third quarter and a good first three quarters of 2017. We are running ahead of plan year-to-date, but as we've been saying all year, we are calling that timing and expect to be essentially flat plan for the year after adjusting for the impact of the IPO, KML, as well as the impact of Hurricane Harvey. Looking back over the first three quarters of the year we have completed the two key steps that we outlined in beginning of the year to strengthen our balance sheet and put us in a position to return value to shareholders. We completed the JV of our Elba Island liquefaction facility in the first quarter, consistent with our budget assumptions and in the second quarter we secured acceptable financing for our Trans Mountain Expansion Project, creating a self-funding entity on the strength of all of our Canadian pipeline and turmoil assets. We continue to expect that we’ll end 2017 with the debt to EBITDA ratio of 5.2 times, versus the 5.4 that we projected at the beginning of the year. Now for a few business segment performance highlights. First, we made promising progress on our Gulf Coast Express expansion project. This 1.9 Bcf a day pipeline would connect growing Permian Basin gas supplies with our existing Texas Intrastate network. We announced earlier this month that we are working to finalize definitive JV documents with Targa, DCP and Pioneer, each of which would bring substantial significant volumes, commitments to the project. We believe that the combination of Targa’s and DCP’s Permian Basin networks and our Texas Intrastate market access provides a very attractive value proposition to our customers. We are in advanced stages on firm transport agreements with core shippers. We've made substantial progress on this since our last earnings call, but we have not yet placed the project in the backlog. We will when we finalize the shipper agreements which we are targeting for this quarter. Second, we're pleased to announce progress on several key projects in KMI. We placed our $130 million Susquehanna West gas pipeline project into service ahead of schedule in September 1. We are nearly complete on three other natural gas pipeline projects, all of which are either on time or a little bit ahead of schedule. These are Connecticut pipeline expansion, our Ryan pipeline project and our Triad pipeline these are expansions on our TGP gas pipeline system, totaling about $270 million of capital spend. We're also a little head of schedule on our $540 million Utopia NGL line, and expect to place it in service in December of this year. We've made excellent progress on this project. Recall, that we discussed on this call, the third for call last year, that we have received an adverse decision on eminent domain in one of the Ohio circuit courts. Our team did an excellent job of acquiring the necessary right of way, including reroutes and the purchase of an existing system. The pipe is now in the ground, all of our HDDs are complete, we're completing the hydro testing and drying of the pipe, and we have final tie-ins in commissioning remain. This was great work by our commercial project management right of away legal and the rest of the organization, to get this project from where it was a year ago to now being ahead of schedule. The backlog is steady at $12 billion, down just slightly from the second quarter update due to additional projects being placed in service slightly more than offsetting projects added to the backlog. In our natural gas segment we saw transport volumes increase year-over-year by 3%, key contributors were Mexico exports higher LNG exports and those were partially offset by lower power demand year-over-year. We also saw slightly more – we saw a slightly more than 1 Bcf, about 1.2 Bcf of new natural gas firm transport agreements with about 100 a day of that being existing, but previously unsold capacity, which, I think, is tangible evidence of the growing demand for natural gas infrastructure both new and existing. Shifting to our Products Pipeline segment, refined products volumes and NGLs are each up 1% year-over-year, crude and condensate volumes are down Q3 to Q3, but slightly up year-to-date. Crude and condensate volumes in Q3 of 2017 were affected by Hurricane Harvey's impact on the refining capacity on the Texas Gulf Coast, which in turn impacted our KMCC system volumes. Volumes on KMCC are now above their pre-Harvey levels. In our terminals business, the segment earnings before DD&A was essentially flat, year-over-year now withstanding the impact of some asset divestitures and the impact of Hurricane Harvey on our Gulf Coast asset utilization. We have also remained aggressive in keeping all of our Jones Act vessels under charter and discounting as necessary to do so. In CO2, we experienced a lower effective oil price compared to last year and lower oil volumes. So we are on plan in this segment, in part due to stronger NGL prices. We've seen some promising progress at our Sac Rock field, where we have begun to delineate and capture volumes from the transition zone. This is a zone just below where we have historically been producing. In three of our projects now we have seen oil from this zone. We have more work to do here, but this is a promising development that will add to the reserves we can target and extend the life of this field even further. We've also maintained our cost discipline in this segment and essentially held the line on costs notwithstanding the rapid increase in Permian Basin activity. A couple comments on Hurricane Harvey, first, our employees responded magnificently to prepare, and respond and recover. Second, as we pointed out many times our cash flows are secured by our contract structures to minimize our exposure not only to changes in commodity price, but also the usage level – usage levels. So for example, we had a de minimis financial impact from Harvey on our interstate natural gas business, where the contracts are reservation based and generally don't require reservation charge credits until after a grace period. The impacts on volume were on volume based charges such as throughput and ancillary charges on our liquids terminals assets, which are – and as well as some of our petcoke operations, our Houston Central processing plant, which operated at lower rates until refiners and the petchems came back up. And KMCC, which as I mentioned, experienced reduced volumes, while the refining capacity was down, but has since recovered to pre-storm levels. So overall I would say a strong quarter and year-to-date at KMI with strong financial performance and continued good progress on project execution. With that I’ll turn it over to Kim.

Okay, thanks Steve. Today we're declaring a dividend of $12.50 per share, consistent with our budget. On performance, first let me highlight a few points and then I'll take you through the details. I’ll start with the GAAP numbers and then I'll move to DCF, which is the way we look and think about the numbers and performance. On earnings per share, third quarter earnings per share is up $0.25 or 249%, versus the third quarter of 2016. However, the way we look at it adjusted earnings per share, which includes certain items is flat, versus the prior period. Our DCF per share, which is the primary way we judge our performance is $0.01 lower versus the third quarter of 2016 or approximately $26 million down, primarily attributable to reduced contributions from SNG as a result of the 50% sale in the third quarter of 2016. Reduced revenue due to Hurricane Harvey, higher sustaining CapEx and pension contributions, as well as the reduced contributions from our Canadian assets due to the IPO of the 30% interest in those assets. These items are partially offset by lower interest expense, nice performance on TGP and multiple new build Jones Act tankers entering service. For the third quarter and year-to-date, as Steve mentioned DCF is ahead of our budget, but that is largely timing with sustaining CapEx and natural gas O&M being the largest contributor. For the full year absent the impact of KML and the hurricane very roughly $20 million each or $40 million in total, we would expect the DCF to be on budget. Taking the impact of KML and Harvey into account, we expect DCF to be less than 1% below budget. On the balance sheet, we ended the quarter at 5.1 times debt to EBITDA flat to the second quarter, but down from the 5.3 at the end of last year, primarily as a result of paying down debt with the approximately $1.25 billion in net proceeds that we received from the KML IPO. Currently we're still projecting to end the year at 5.2 times as we previously communicated. But depending on the timing of expansion CapEx and exactly where we land on EBITDA, it is possible that we may end the year at 5.1 times. On expansion CapEx we’re forecasting $3.1 billion for the year that is down from our budget of $3.2 billion. The $3.1 billion does not include any KML CapEx, including spending on Trans Mountain from June forward as we expect KML to be a self-funding entity, i.e. KMI does not expect to make contributions this year to fund KML. Because of the equity that KMI contributed to fund the Trans Mountain Expansion prior to the IPO, KML has the capacity to draw on its construction facility to fund its CapEx for balance of the year. Now let turning to some of the details. Looking at the preliminary GAAP income statement, you’ll see that revenues are down by 1% in the quarter and that cost of sales is up resulting in $107 million reduction in gross margin. Typically when we see revenues down, we also expect to see cost of sales down. But the sale of the 50% interest in SNG accounts for $83 million or just under 80% of this variance. Therefore excluding the SNG transaction, gross margin would be down 1%, which is pretty consistent with how we – how we view our overall results for the quarter. Net income available with common shareholders in the quarter was $334 million or $0.15 per share, versus $227 million, or a loss of $0.10 per share in the third quarter of 2016. More than all of the $561 million increase is explained by a $576 million change in certain items, on which I will give you some details in a moment. After certain items net income available to common shareholders is down $15 million and earnings per share is flat to the 2016 numbers. Certain items in the third quarter of this year were a benefit of $6 million. Pretax certain items were an expense of $47 million the largest driver was $32 million in expense associated with the change in fair market value of our derivatives contracts, which are primarily used to hedge our commodity exposure in CO2 and our midstream natural gas business segment. We reflect the impact of these hedges in DCF when the physical transaction occurs. You will also notice $9 million associated with Hurricane Harvey. These are largely repair costs, for example, cost to repair or rebuild motors, pumps, and actuators due to flooding damage in our Houston Ship Channel facility. We expect that we'll have additional repair costs in the fourth quarter and that these repair costs will be recoverable from insurance subject to our $10 million deductible. You’ll often notice that there is a certain item tax expense, which is a benefit of $53 million dollars. A significant portion of the benefit is associated with being able to claim the enhanced oil recovery on our 2016 tax return as opposed to only being able to claim the deduction. Now I'm going to turn to the second page of financials which shows our DCF for the quarter and year-to-date and is reconciled to our GAAP numbers. As I said earlier, DCF is the primary financial measure on which management judges this performance. We generated total DCF for the quarter of $1.055 billion versus $1.081 billion for the comparable period in 2016, down $26 million or 2%. Looking at the breakdown of the quarter-to-quarter change, segment earnings for DD&A and certain items is down $29 million. Natural gas is the driver down $31 million. All of the $31 million and more is associated with the SNG transaction, which had roughly a $15 million impact quarter-to-quarter. At the CIG rate case and reduced volumes on some of our midstream gathering and processing assets also impacted the segment in addition to Hurricane Harvey. We estimate that Hurricane Harvey impact on our natural gas segment to be under $10 million, which is our estimate of the revenue that we did not collect primarily in this segment as a result of our customers being offline during the storm. The cost that we are incurring to repair our assets and that we expect to be reimbursed by insurance, subject to the deductible are included in the Certain Items. This is consistent with how we have treated other hurricane impacts in the past, where we reflect the damages as a certain item expense and the insurance proceeds when we have a proof of loss as income. After the SNG sale and the estimated Hurricane Harvey impact, the natural gas will up slightly, primarily as a result of expansions and capacity sales on TGP, EPNG and the Elba Express expansion. The CO2 segment is down to $12 million or 5%, primarily associated with slightly lower oil production approximately 350 barrels a day net and a $4 per barrel lower oil price. The terminals and product segments are up $12 million on a combined basis offsetting CO2. Products and Terminals would have been up over $35 million, excluding the combined impact of Harvey and our two terminals divestiture. This increase was driven primarily by new-build Jones Act tankers placed in service and nice results on our refined products assets. The Kinder Morgan Canada variance is small, G&A is $4 million lower quarter-to-quarter, interest expense is lower by $40 million in the quarter versus the third quarter of 2016, as a result of lower balance just slightly offset by higher rate. We use the proceeds from the SNG joint venture transaction and the KML IPO to pay down debt. Sustaining CapEx is higher by $22 million versus the third quarter of last year. As you may remember, we budgeted for 2017 sustaining CapEx to be higher than 2016. Cash taxes are lower by $13 million as we were able to defer certain payments until 2018 as a result of the hurricanes. Other items were higher by about $24 million as we made a cash pension contribution in the third quarter of 2017 and we did not make one in the third quarter of 2016. KML impacted by about approximately $8 million in the quarter net. The direct impact is reflected in non-controlling interest which reflects the public share of KML’s earnings and that impact is somewhat offset by interest savings. Totaling the quarter-to-quarter variances, segments down $29 million, $44 million benefit from G&A and interest and a $33 million combined increase in expense from sustaining CapEx, cash taxes and other items as well as approximately $9 million KML impact, results in a DCF change of approximately $27 million versus the $26 million actual change. DCF per share was $0.47 in the quarter versus $0.48 for the third quarter of last year are down $0.01, all of which is associated with the DCF variance, I just walk you through. $0.47 per share results in over $770 million of excess distributable cash flow above our $0.125 dividend for the quarter and almost $2.5 billion year-to-date above our declared dividends. As I said earlier, for the quarter and year-to-date we are ahead of our budget but for the full year we expect to be on our budget, excluding the impact of KML and Hurricane Harvey. Excluding the impact of those two events, we would expect DCF to be less than 1% below budget. With that, I’ll turn to the balance sheet. From a balance sheet, we ended the quarter net debt of $36.467 billion. There you'll see two lines on the balance sheet this quarter, the second line is our net debt including 50% of the KML preferred which is the treatment we get from that preferred with the rating agencies 50% has been treated as debt and 50% is treated as equity. So when I reconcile debt, I mean reconcile the net debt, the first line net debt $36.467 billion that's down $1.69 billion year-to-date and down $134 million in the quarter. So in the quarter down $134 million, DCF was $1.055 billion, we spent $822 million on expansion CapEx and contributions to equity investments. We paid dividends at $280 million, the proceeds from the KML preferred offering were $230 million. Asset sales which was primarily in our terminal improvement of $47 million, we got a tax refund of $144 million, we paid a legal settlement of $65 million and then working capital and other items for use of cash of $175 million. But the two largest uses being accrued interest which is about $114 million and then the other use of cash being timing on JV distributions and debt repayment down at the JV of about $40 million. Year-to-date debt has increased $1.69 billion, DCF was $3.29 billion contributions to equity investments and expansion capital, $2.47 billion, paid dividends of $840 million, the IPO proceeds on KML and the KML pref are $1.475 billion, asset sales and JV proceeds for cash source of $504 million, the largest of which was the Elba JV. We got a tax refund of $144 million, a legal settlement of $65 million and working capital and other items for a use of cash of $350 million with the largest uses of cash being accrued interest of $158 million and that’s because we primarily make our interest payments on our debt in the first and the third quarter. Debt issuance fees of approximately $70 million, most of which was associated with the Trans Mountain financing that we completed in May. And then inventory and gas purchases for a use of capital of about $100 million primarily as the Texas intrastate get ready for the winter season. And as I said earlier, we ended the quarter at debt-to-EBITDA of about 5.1 times, we still expect to end the year at 5.2 times with maybe some chance that we come at 5.1 times. With that, Steve, I’ll turn it back to you.

Okay. Just a reminder on KML, KML consist of all of the Kinder Morgan Canada pipelines and terminals assets and those include our existing Trans Mountain pipeline system which runs full and is the only outlet for Alberta Crude to the world oil market, also includes our Puget Sound System, which takes oil from Trans Mountain and delivers it to Northwest Washington State refineries it includes Canadian portion of the ocean delivering condensate to Alberta for blending with the oil sands crude as part of the transportation, so crude comes down from the oil sands to our merchant terminal position in Edmonton, we have to move on Trans Mountain or other pipelines or through one of our joint venture crude by rail facilities. We've built our Edmonton tanks position over the last 10 years and continue to expand it with our Base Line terminal joint venture with Keyera, which is on time and on budget with first tanks coming on in early 2018. Finally Vancouver Wharves, our multi commodity bulk terminal in Vancouver harbor and the gateway terminal for mineral concentrates into and out of Western Canada is also part of KML. So in summary, KML was comprised of two strong existing business platforms that are integral to fulfilling the transportation blending and storage needs of producers and refiners in Canada. And it has the substantial upside associated with the Trans Mountain expansion. On that expansion, we call that in Q1 of this year we reached a milestone. We increased the cost projection above the cap which gave the shippers the right to return capacity to us when all of a sudden done, all the capacity was placed that’s reaffirming the market need for this project based on 2017 shipper line up and 2017 oil sands economics. I'm repeating this because I think it's worth bearing in mind as we go through the various ups and downs in this project that this product is vitally important to our customers. Also recall that we have built-in protections for the costs that are more difficult to estimate and control, these uncapped costs associated with the more difficult mountain build and the urban portions of the build. If higher than our cost estimate result adjustment to our toll which includes costs and also the return by the same token reduce cash flow through to the benefit of shippers and our shippers benefit from any other portions of our costs that are capped if we and we absorb the overrun if any. We also have our federal approval and our BC environmental approval in hand. Okay, so now the key for us on this project is access to land and permitting so that we can be confident the ability to officially construct this project. We recently received some good news on that front as we receive permits from British Columbia granting access to nearly half of the Crown land parcels that we need in British Columbia. We also received this week permits from Alberta granting access to many of that provinces, Crown parcels as well. These are undoubtedly positive developments and they've occurred very recently. However, the pace of the permitting process and therefore our overall construction activity has started off slower than we planned. So as we said in the KML release without mitigation what we have experienced so far translates into the delay of up to nine months. Again the recent progress of permitting is promising but we need to continue to seek ways to accelerate that progress. Also as we will continue our review of the construction schedule and mitigation, we will manage our spend prudently and wisely to maximize shareholder value. For example our full year budgeted spend for 2017 has been reduced by about CAD340 million and we reduced our forecast for the balance of the year by about $160 million from our previous internal forecast in the last forecast that we made. I think this is very tangible evidence that we're going to continue to be careful stewards of KML shareholders capital. As we continue the permitting in the development of this project. And with that, I'll turn it over to Dax for the financial update on KML.

Thanks Steve. Before I get into results and outlook I want to highlight a recent occurrence in the bank capital markets front. During the quarter, we completed our first offering in Canadian rate reset preferred stock in August, we launch [indiscernible] $200 million in response to significant demand we were able to upsize the $300 million in price with the five and a quarter coupon which netted us approximately $293 million in proceeds. As a reminder, our plan for financing the project contemplates that we will raise $1.5 billion of preferreds during the construction period and those preferreds get 100% equity treatment under our construction facility and generally 50% to the eyes of the rating agencies. Overall the success of this offering was yet another positive step towards KML raising the capital necessary to fully finance the PMX expansion. As I alluded to our viewed results, as I did last quarter I want to preface my comments with the caveat that while will be offering quarter-over-quarter comparison these comparisons have limited value at this point given that we are reporting a quarter where KML was done by the public and will be comparing results for the quarter where it was wholly-owned by KMI and during those periods part of the IPO, there were shareholder loans in place that generated significant FX most of which is unrealized. Interest and other items not reflective of the true earnings power KML therefore we would ask you to focus on the outlook for the balance of 2017 which you will see is consistent with what we've previously discussed, quarter-over-quarter branches will need more of a time and obviously we don’t have a published budget for KML, a standalone company but starting with our budget cycle this year we will publish one just as KMI does. Now moving into the results and outlook for the rest of 2017. Today we're announcing the KML board, declared dividend from third quarter of 0.1625 per restricted voting share or $0.65 annualized which is consistent with previous guides. With respect to earnings and net income, earnings per restricted voting shares of $0.11 for the quarter which is derived from approximately $42 million of net income, which is up over 100% from approximately $20 million of net income for the same quarter in 2016. That increase is due mainly to lower interest and foreign exchange associated with intercompany loans that were set with the IPO. Adjusted earnings was approximately $42 million, compared to $36 for the same quarter of 2016 into the more reflective of the business performance as it excludes certain items which I will discuss in a minute. With respect to the DCF, DCF per restricted voting share was $0.214 for the quarter which is derived from total DCF for the quarter of approximately $77 million which is flat to the comparable period for 2016 that provides coverage of approximately $5.4 million reflects a payout ratio of approximately 76%. Segment EBDA before certain items is up $1 million compared to Q3 2016 with a pipeline segment up approximately $300,000 and the terminal segment up about $700,000. The largest moving pieces within the segments are higher AEDC at Trans Mountain ancillary fees at the Edmonton south terminal offset by lower cubic volumes and a contracted throughout, see reduction at the Alberta Crude terminal JV that was implemented in Q4 last year. G&A is higher by approximately $1 million with a largest contributor being audit fees associated with being a public company. Interest cost is $5.7 million lower versus Q3 2016 primarily as a result of the repayment of the intercompany loans and greater capitalized interest associated with projects. Total certain items for the quarter were 400,000 tax affected with most of that being unrealized FX associated with small intercompany interest payable that was tied to the larger loans between KMI and KML that were extinguishing. That payable was cleared up at the beginning of the third quarter and should not create any further FX. Sustaining capital was unfavorable approximately $4 billion compared to the same quarter in 2016 due largely to the time we spent on Trans Mountain mainline and overall higher spend in the terminals. CapEx is we’re essentially flat compared to the same quarter in 2016. Now moving on to some specifics of the full year 2017, we expect EBITDA for the full year 2017 including pre and post IPO periods to between $380 million to $390 million and we expect DCF to come in between $350 million and $320 million. A decrease in expected DCF from $320 million that we mentioned last quarter and $315 million to $320 million is primarily attributable to lower AEDC associated with lower expected spend on the Trans Mountain project versus what we expected at the end of last quarter. These expectations are consistent with $395 million and $318 million 2016 EBITDA and DCF respectively that we highlighted during the IPO. With that, I’ll move on to a few comments on the balance sheet. For the end of the year 2016 to September 30, the cash increased approximately $101 million which due to $240 million of DCF plus $293 million of net proceeds from the preferred offering I mentioned and $165 million net draw on the construction facilities that I mentioned offset by $392 million of cash, actually paid for expansion CapEx $75 million paid for debt fees, $15 million of distribution net proceeds and $45 million working capital/other use of cash. PP&E increased $359 million, which is primarily due to spending on expansion project. Deferred charges and other assets increased approximately $86 million which is primarily attributable to unamortized debt issuance cost on the construction and working capital facilities. On the right hand side of the balance sheet, short-term debt increased by $165 million which is the balance on the construction facility. The $500 million working capital facility had zero balance. Other current liabilities decreased by almost $159 million, which is primarily result a decrease in quarter end, intercompany payables from KML entities to KMI which we’ve endeavored to minimize since the consummation of the IPO long-term debt decreased by almost $1.4 billion to zero and that was a result of paying off the intercompany loan. As you can see, we ended this quarter with net cash of approximately $165 million even after adding 50% of our preferred equity to our net balance we are still in net cash positive position of $15 million. With that, I’ll turn it back to Steve

Okay, with that, we will take questions on KMI and KML. Okay, Brendon.

Thank you. We will now begin the question-and-answer session. [Operator Instructions] And our first question is from Jean Ann Salisbury with Bernstein. You may begin.

Hi, good afternoon. I just had a couple on Gulf Coast Express it seems like since Permian flows to Mexico have not really materialized yet, the outlook for Waha in the next year or two keeps getting worse. Can you speak to whether it seems like Permian – those are getting more noticed about in basin pricing for gas over the last six to nine months.

Okay, well, I will see if Tom has any other color, not speaking to their nerves but really just speaking to the fact that the contracting process goes – is going a lot faster I think the people are realizing that perhaps here’s another way that they need to get out of Waha, that the volumes going to Mexico as you said are not materializing as quickly maybe as the pipeline capacity to move to Mexico has materialized. And so now with the Texas Gulf Coast becoming more of a premium market, shippers are definitely looking to get there. I think that’s fair to say that tangibly is showing up in the FPA agreements that we are working on with them. So when they get eased they obviously observe the basis differential between the Permian today. And what it is in Houston ship channel when they get eased to our system they can access Mexico through our connections with Mexico including a pipeline that serves Monterey, they can also access the emerging LNG liquefaction capacity that is coming on line on the Gulf Coast plus the petchems plus the Houston area utility power demand in industrial market. And so I think it gives, speaking – not speaking for the shippers but I think it gives producers the option to exploit a large number of different and varied market and not that on or depends solely on what the prospects for power demand growth in Mexico are.

Make sense. So it really has picked up over the last quarter it sounds like?

It has.

Okay, and then [indiscernible] FID and still hit second half of 2019?

Well, we talked about, we didn’t talk about FID, talked about adding it to the backlog I mean I think we are hopeful and working toward trying to get things resolved and done this quarter and I think we are making very good progress on that but its not completely done. And Tom in terms of the – sometime this quarter as we need to get it done.

Okay. And the 1.9 is that kind of the maximum on that diameter, no real expansion CapEx?

Yeah, I think that’s max.

Okay, great. That’s all from me. Thank you.

Our next question is from Tom Abrams with Morgan Stanley. Your line is open.

Hi, Tom, how are you this afternoon?

I’m good, thanks. Just – before I ask my question, a quick follow-up on the Gulf Coast is the first question. Do we have a cost number for your portion yet?

We have not put out a cost or return numbers because it’s a competitive situation out there. But we have a 50% interest that we are contemplating we could go below that to the extent that we end up cutting additional equity yield and exchange for significant volume commitments being brought to the project.

Okay, we’ll wait on that then. But my question was on recontracting I think in your 17 Analyst Day, you gave like it was 1.5%, 1% for 2018 and 2019 respectively on what was the risk you thought which is really quite modest. Is there any reason is in developments why that should more or less as you see it now?

I mean nothing material that I can speak to at this point.

All right, and then attach to that a little bit, I think you heard say in your working capital comments, what Kim said, a $40 million debt pay down at the pipeline level. Correct me if I’m wrong on that particular fact. But do you see additional requirements to make pipeline level debt pay down through 2018?

The $40 million just refers to in aggregate, the difference between the DCF that is in – what’s in our DCF and what we got in distributions from equity investments. And so in some cases, we have at that level that has amortization payments with it and that’s primarily Ruby, and Gulf LNG have some. But that number also just includes timing, whereas sometimes there’s a quarter lag between the DCF and and the distribution coming out.

Got it. And then second part of the question in terms of anticipated pipeline level debt pay down?

Anticipated at joint ventures other than amortization, I mean we have a maturity, I guess on Ruby next year of about $250 million and we have a maturity on FEP next year of about $250 million. And so we have – as we go through the budget process we’ll decide whether we refinance that debt or whether we pay it off.

Alright great. And then if I could stick one more in just looking at some of the kind of quickly hear what you’re talking. So maybe not accurate, but the sales volumes and some gas gathering numbers in the gas segment seem to be declining a little bit, any commentary around that?

Yes, we had, I think, we had sales volumes down on the interest rates for transport volumes up, right, in almost equivalent amounts. But on gathering and processing we have – we think we’re starting to see some sequential month to month pick up in gathering volumes. But we have experienced certainly on a year-over-year basis declines in the key basins in which we access. And in some cases those declines have exceeded what the overall basin decline is, I think, the key example there is Haynesville, which is actually grown year-over-year. The primary shipment that we have there has not been an active exploiter of what we think is very good rock is under their acreage. We expect that’s beginning to change. But we haven’t seen the recovery there yet. So we’ve seen declines that are commensurate plus a little more, I’d say than declines that are overall apparent in the basins from Q3 of 2016 to Q3 of 2017.

We expect growth in the fourth quarter, so we feel like we’ve bottomed out pretty much also all our more gathering systems.

All right, that’s great. I’m sorry.

Tom, coming back to Kim’s answer on Ruby and FEP those are both eight-eights she gave you we obvioulsy own half of each of those pipelines.

Alright, thanks for that. I’ll get back into queue. Thanks a lot.

Our next question is from Shneur Gershuni with UBS. Your line is open.

Hi Shneur, how are you?

Good, how are you Rich.

Great.

Just a couple of questions maybe the sort of follow-up on Gulf Coast Express. I realized because you are in a kind position you can’t discuss capital costs, but on a previous call you’d mention that it would be north of a $1 billion. I was wondering if it’s possible to put an upper range in terms of the entire project cost as…

I think last time I said $1 billion to $2 billion. And I’m sticking to it.

Great.

I mean it’s fairly transparent. We just don’t want to give our competitors any particular insight into our cost there Shneur.

No, it’s fair enough. And really she can’t talk about returns by, is it you should if we think about it in terms of your current project backlog would it be kind of similar to kind of the returns you typically expect or could it potentially be higher or lower?

Yes, I think comparable to gas backlog.

Okay, great. And then with crude sort of stabilizing a little bit in some of your hedges are now rolling off on – in the C2O segment. Are there any plans to revisit potentially selling this segment or doing something with this segment?

We can’t comment on that in any kind of a specific way about potential transactions, but look we can say again that we like this business. We’re happy with this business. We get attractive returns on the capital that we invest. I think we’ve got two specific businesses and niche business for us, but we have two very key advantages that we bring to it. One is access to CO2, which is a scarce commodity. And the second is a really talented EOR team that knows what they’re doing with the enhanced oil recovery fields that we have. And so we’re happy to continue to own this business and think we bring real advantages to it. But it is a niche business for us.

Okay. And then a final question with respect to the share buyback that annonced last quarter, do you see any scenarios where you can potentially execute it at a faster pace than this kind of the three-year plan that was outlined certainly given where your stock prices are currently at?

Well, our intention is to execute over that three-year period. And as far as the exact timing and clearly we are not happy with our stock price right now, its trading in it, is a whole midstream sector is not trading well and we’re trading poorly, particularly on price to DCF basis. But the share buyback is part of the long-term plan of return value to our shareholders and the implementation of that is going to be just as we said in 2018, 2019 and 2020.

Okay. And one final question. Do you haven’t have the CO2 CapEx spend for this quarter?

Yes about $100 million.

Great. Perfect. Thank you very much guys.

Our next question is from Brian Zarahn with Mizuho. Your line is open.

Good afternoon Brian.

Hi Rich, how are you?

Good.

Just following-up on the buyback question in the scenario that the midstream capital market – equity markets remains soft, is there possibility to expand buyback authorization and potentially not grow just the dividend as much in the out years?

Well, we’ve said Brian repeatedly that we intend to return all of our operating cash flow above our capital expenditure level to our shareholders and either dividends or stock buybacks. And we’re on record is saying what our dividend policy is for the next three years. So I would anticipate we would follow that. Now certainly if you get beyond that period of time and I’d certainly believe this will be the case that you have a disconnect between what we believe the disconnect between evaluation and where the stock prices we would look at it differently. But for the forseeable future, I think, we’ve committed to this dividend policy and this share buyback policy, and I think that’s where we are at this point.

Okay, fair enough. Shifting to Trans Mountain, perhaps if you could clarify a bit some of the prior comments that you still expect late 2019 as of now if you can execute on these contractor efficiencies otherwise as a nine-month delay. And then potentially can you just discuss a bit more about the unfolding events in courts and how we should think about or likely an appeal from – on this case and if I can better understanding of the parameters of the potential and the service date?

Okay, yes, I think there’s really not a lot to add to what’s in the release, which is that if you just as the delays experienced to date and just flow that through the schedule, we believe that results in a nine-months delay, but that’s unmitigated. And we also have a case where with with a lot of mitigation, and with several assumptions we can call back to the December 2019 in service day. And so there’s work to be done on mitigation, there’s work to be done on on permiting, and working with our contractors, which we really haven’t had an opportunity to do in terms of bringing them into examine our assumptions on cost, and schedule and the rest. And we’ll be doing that over the coming weeks and months. In terms of the the appeals, we think a couple of observations there. So there’s the BC provincial approval, there’s the federal Order in Council. The BC provincial approval we think it’s very worthy of note that the current BC government is defending the EA, the environmental assessment order, in terms of the adequacy of consultation with First Nations by the prior BC government, okay. And so I think that’s a noteworthy development, that’s a development within the last few weeks really. On the Order in Council, what we would say the federal order, is that we believe that we and the federal government did everything that the Northern Gateway order advised us to do in terms of additional consultation work suddenly we think the federal government did an excellent job of defending the orders that it issued and took into account all the relevant matters. It’s always hard to predict court proceeding outcomes. And what happened and whether someone takes an appeal or not. Appeal is not automatic to the Supreme Court of Canada, just like it’s not automatic here. But again I think it’s noteworthy that the D.C. government is defending the prior order and, I think, it’s also noteworthy that the federal government did a lot of additional consultation and additional work in order to meet the concerns that we identified in the northern gateway decision.

And then just lastly, if there is an appeal to the federal Supreme Court, how do you think about timing in that scenario?

Again very hard to predict or project. We’ve had experience with our Anchor Loop Project, which was a project that we felt through the national and provincial park and we had NED certificate or NED order it was appealed, we prevailed on that appeal. Ultimately appeal of that court decision was denied. And so it’s – just it’s it’s hard to know how that would play out until we see the facts.

Thank you, Steve.

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

Hey Darren, how are you?

I’m fine thanks, Rich, I hope you and everybody doing well. Steve, I just had a quick question for you on Gulf Coast Express. And I appreciate that from a volume commitment level it’s still very fluid as you guys finalize ship agreements. But you’ve discussed before having access to one Bcf/d of gas across the system Texas Intrastate taking out BPNG volumes as well. So how do you balance the economic decision with regard to how much gas on the line you could source both on KMTP and EPNG and have the ability to get that synergies to got with in terms of capacity utilization upstream of the pipe versus what could be 0.5 of Bcf/d with associated gas coming out of the sealed gates [ph] of targets processing plants and of course what DCP you would contribute from their assets including what they’re going to do at sand hills?

Darren as always you load a lot into a question. I think what you’re getting at those is how do we look at getting in transport commitments versus purchasing the gas ourselves, which we need for our Intrastate State Texas portfolio of sales activities now which you’re – what you’re getting that.

Yes.

Okay, okay. That is something we’re looking at, I think it’s fair to say that we are first and foremost filling out with 10-year transport commitments. But there’s definitely a benefit to us accessing additional sources of gas particularly as we’ve seen both declines in the Eagle Ford maybe leveling out now, but also an overcapacity out of the Eagle Ford. So adding to our sources of supply as you say, is a positive and it is something that we’re evaluating that is entering into a purchase agreements for supply that we can use for our own system needs.

Thank you.

Our next question is from Danilo Juvane with BMO Capital. Your line is open.

Thank you for taking the questions. How are you guys today?

Good.

Good. Quick question from me on Utopia. None of the pipeline has shift to ethane only, does that at all impact the contracted volumes on the pipeline?

No, there’s no change to the contracted volumes.

Got it. And you guys filed year-to-date assumptions in Gulf LNG. I was wondering if you had any updates on the arbitration process there and when you’re planning to the ultimately advance this of course your liquid fashion?

Yes, so two things. Really the arbitration is proceeding, we believe our case is exceedingly strong. We may get a result by the end of the year in that case. In terms of opportunities on Gulf Coast liquefaction those are things that we continue to evaluate. But I think looking at kind of the worldwide market situation for LNG, we’ve got the current buildout taking place really across north – across the country, across the U.S. And then I think most analyses which show that it’s really 2023 to 2025 before we see another significant uptick and demand. And so we may be waiting until, now you have to start earlier than that to meet that demand. But we may be waiting until the market is ready to start addressing that increase in demand. So that’s ways off.

I appreciate that. One final question from me. You announced, I think, one project on SNGs to Fairburn Expansion, is that the only project that we’ve announced since that the JV was announced by the company?

Yes.

Do you see visibility to any incremental growth or expansion as a result of this JV going forward?

I mean there are certainly opportunities that we’re discussing with our partner and in the marketplace. So I would expect that we’ll see more overtime.

Yes, fair to say too, it takes time, Fairburn Expansion is preceeding well, they have third-party shipper interest and contracting for capacity on that expansion. So I think that’s going well, according to plan.

Our partneship with Southern Company is a very good partnership both from our standpoint and their standpoint.

Do you have any sort of order magnitude as to what incremental growth could be from that?

Yes, not really an estimate that, I think we can give you at this time.

Okay. That’s it from me.

I think it’s working according to plan. I mean when we announced that transaction and the things that we thought about that transaction at the time not just the balance sheet benefit that we would get, but the value of associating ourselves with Southern Company an active developer of gas-fired generation capacity and a large customer on the system I think those are materializing. And I think the working relationship is quite good.

I appreciate the answer. Those are my questions. Thank you.

Our next question is from Colton Bean with Tudor, Pickering, Holt. Your line is open.

Colton, good afternoon.

Good afternoon. So I just wanted to speak on the Nat Gas team. You guys are currently moving to the permitting process on the NGPL Southbound Expansion project. So just assuming that project goes ahead, how much more reversal capacity would you have available and just looking at a couple years you’ve got Rover and Nexus and ultimately the Alliance expansion dropping up quite a bit gas in the Midwest. So it seems like all that will be looking to find a home further south. So just maybe timing and thoughts around any potential projects beyond what you currently got queued up?

I mean I think there’s now probably 250 to 400 more that we could do the additional expansions and that that’s probably another couple of years out through the thrid process, but those discussions are ongoing with Gulf Coast customers as well as even Canadian producers some extent as well as producers also of Rockies Express.

You’ve identify I think the right trend there, which is we do think that there’s going to be Canadian gas that wants to find its way to another market further south and we think that there will be – there will be additional westbound supplies coming into NGPL that also want to get south to Mexico, to LNG, et cetera.

Got it. Thanks for that. And I guess so you’ve touched on Utopia, I think, you’ve also just recently received authorization for [indiscernible] on TGP, so just thinking about you and TGP kind of longer term thoughts around NGL takeaway from the northeast, where do you guys stand on that currently?

Yes, correct. We did get the advantment it is a project that we continue to work on. I think, but there’s nothing new to update or material to update there at all. And I think that there will be with all the expansion capacity coming to takeaway capacity coming online, and production presumably increasing behind it. I think that there’s a bit of a wait and see in terms of how much NGL capacity, is how much NGL production is going to want to find a way home and where it’s going to want to go, what the impact of the Shell facility is going to be in Pennsylvania and the other expansion projects out of it – out of the basin. So I think there’s – there are several things that have to play out over the coming months.

Okay. So just continuing to advance the project, but nothing really new to comment on that.

Right.

Got it. Alright, well thank you. Helpful.

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

Good afternoon Faisel.

Hey, good afternoon Rich, Steve and Kim. Just a couple of questions. Just I want to understand some of the text in the press release around Trans Mountain. The nine months, nine months delay is that – how I figured that into the uncapped versus the capital cost of the line. Understanding that you can completely mitigate that cost if you could?

Yes it’s really, Ian you want to answer the question.

Yes, I don’t think nine-month, It’s Ian Anderson, I don’t think the nine-month delay scenario that we could be based with have a bearing on the capped versus the uncapped. If we have additional AFUDC, for example, over a period it would flow equally to proportionally to the capped and uncapped as it’s currently fine.

Okay understood. And then if I understand the Federal Court appeals case right now, and there what you’ve heard, I guess old arguments and briefs. So I mean this sounds like if just one of the final thesis of a ruling that you need, I mean what else am I looking at here? My understand some the stuff around the DCEO, but for FCA, I mean if you – once you get this ruling is that what else and what are the challenges can be assume not be against you?

I mean, we have the ruling that we need in terms of the federal government’s order and council. It’s just that order in council is being appealed. The fact that there’s appeal and depending on the outcome of the results of that appeal doesn’t mean that we can’t construct and we encountered this in the U.S. as well where somebody might be appealing an aspect of a first certificate, for example. But depending on what the court finds and if it does find an infirmity depending on what that infirmity is, that doesn’t necessarily stop us from continuing to progress the project. So look we can’t predict outcomes of court proceedings and this is the key one, there’s no question. But we have the authorization that we require from the federal government.

And depending we see to some of the further permits and approvals is that mutually exclusive of the FDA or is there any link to that?

No, those are different things, those are different things. So for example, what we’re talking about and what we received here just recently Friday of last week and then Tuesday, I guess right this week were permits from the Alberta and British Columbia provincial authorities giving us access to crown lands. So that’s a separate – that’s a separate set of permits, not having to do with the order and council that’s on appeal in the federal court.

Okay, okay, got it. And then shifting back to the U.S. on the – regarding on processing side, so I just want to understand just the commentary on this. So the volumes are down about I guess 5% or so sequentially quarter quarterback, I guess the 150 million a day or so to 2.5 Bcf/d. We’re just trying to understand like, how much of that was related to hurricanes and how much was sort of the base decline rate taking place in these two businesses, I guess?

Okay I’ll ask Tom to give you any other specifics that he has. So our volumes are gathered volumes if you look from 2Q to 3Q of 2017, would have been affected by the hurricane. And so what I mentioned earlier the petchems shot in that’ll have a cascading effect and refineries, that will have a cascading effect upstream to like gas processing plants like our Houston Central plant, for example, where if we’re not processing the gas, we can’t put it in the gas stream because it won’t be quality specs, it hasn’t been dried out, the liquids have to be extracted.

Okay.

And so then in turn that box if you will upstream to the producers who have to be shut in if their gas is too rich to be taken into and it’s not pipeline quality gas. Now there whether Harvey effects like some producers got effectively rained out there and had to shut down their operations. We had situations where if they couldn’t control pressures, we couldn’t take a physical risk. And so there are a number of factors. That would definitely have an impact on 2Q of 2017 to 3Q of 2017 volumes, obviously in the Eagle Ford. When I was talking before I was talking about 3Q of 2016 to 3Q of 2017 and the fact that we were having gathering volume declines there, some of which are explainable by the difference between those two periods in the basin performance, right which again we’re starting to see level off and turn around now. You got to do this basin by basin almost. But also some of it is, I think, we’re running a little behind basin volumes here too. And that’s a function of where people are maximizing – where people are optimizing, where they have minimum take obligations, for example, and a number of other factors.

Well, I guess, let me ask it this way then. Are you back up to the two points, the declines have flattened out in 2Q versus 1Q, and look like, you look like if that working we’re going to be flat sequentially. But is that a fair statement, when I look at where you are today do you have a number today we worked on.

Well, the biggest single area that we saw declines from Q2 to Q3 was in Copano South Texas, which was the Eagle Ford. And yes we are back up to pre-storm volumes here early in the fourth quarter. We also fall somewhat of a decline on our Kinder hub system and that’s largely dependent on BHP activity, which we view that as timing that will we expect to growth volumes there as we proceed into the fourth quarter and into 2018.

Okay got it. The last question from me, just on the Jones Act tanker market, where you guys seeing rates right now and how are things sort of trending and I guess another vessel and truck. Where are the spot rates and where do think things are right now versus a quarter ago?

John Schlosser is the President of our Terminals Group this year, so John.

Sure. Our rates in 2015 we were roughly 62,000 a day across the entire fleet. Last year they hit a high watermark around 67,000 a day. And because of the decline this year we’ve seen them come back down the 62,000 a day across the entire fleet. That’s an average fleet.

Average fleet, correct.

Okay and then – if the end demand is that coming back or if some of these contracts roll off?

The market is continued to soft. We anticipate that same soft through 2018, we think that will be more like 2019 now.

Okay that’s very helpful. Thanks guys I appreciate it.

Our next question is from Jeremy Tonet with JPMorgan. Your line is open.

Hi Jeremy, how are you?

Good thank good afternoon. Just a couple of quick clean up questions here. Just want to make sure as clear as far as the hurricane impact on your results for the quarter and how you’re treating it. So for the $175 million of EBITDA that would exclude any damages, but lost business for the quarter would be included in that number. Is that the right way to think about it?

Yes.

That’s correct.

Okay. So it would have been even higher, gotcha without that. Thanks. And then as far as going through the portfolio that you guys have right now and thinking about non-core assets, do you guys think you’ve kind of completed that process at this point or are there other things that you might look to – you might look to sell at this point?

Yes, I think we’ve done some divestitures of non-core assets, particularly in the Terminals Group in our bulk terminals business. There’s nothing that I would say is currently on the list, but it’s also something that we continue to review, and evaluate and see if it makes sense if we get a higher price in somebody else’s hands, whatever higher value in somebody else’s hands if you need to work on the balance sheet, et cetera. But I think we’ve done a lot of that work already.

That’s helpful. That’s it from me. Thank you.

Our next question is from Robert Kwan with RBC Capital Markets, your line is open.

Robert, how are you?

Good, thanks Rich. Just on the Trans Mountain permit, I’m wondering you have a number of how PC permits were needed when the NDP came in and how many had been granted post the change of government?

Yes, Robert it’s Steve. It’s difficult to boil it down to those numbers, given the fact that there are so many, for example, Ministry of Transportation, permits that we require of BC, north of 900. And those will come kind of in bundles by location geographically that we’ve prioritized. And what I can say is that the parcels and tracts of land that we got access to this past week were 327 of 631. So above a little more than half of all of the BC Crown land access that we needed, we were granted last week. We’re working hard on the process to satisfy the condition or satisfy the permit requirements for the Ministry of Transportation. But there’s tough to them and many of them marked really required as for construction schedule to next year, depending on location. We’re working hard on kind of the Northern interior sections spread three and four. There’s probably about 80 there that we’re anticipating were seen up soon. And then there are a number of smaller ones related to things like wild life and stream access, but the number overall is well over a 1,000 that we need from the British Columbia. And we’ve continued to get in the hundreds since the NDP took their seat. And I think the other message there Robert is that the bureaucracies and the statutory authorities of BCF continue to do the work. We don’t get to see any evidence of any political influence.

I understood. And with the lower 2017 spending estimate just drilling down into the nature of that, is it pretty much all just a delay in what you’re going to have to spend on contractor and construction activities or are you also delaying some of the ordering of longer lead time materials?

No it’s essentially all related to delays in permitting out approvals and conditional release that we need in the varying sections of construction and land access would be a part of that as well.

Let me just add that as we’ve said in the release and Steve as said, the permitting has been slower than we expected it to be. And we certainly need that permitting in order to build this project obviously and what we’re doing here and I think Steve and Ian are doing a great job on it. We’re not going to waste shareholder money. We’re being very careful on how we spend the dollars because of the situation that we’re currently in and that’s the numbers as Steve gave you and we’ll continue to look at spending levels as we go forward and then just in accordingly.

Okay, that’s actually great lead in my final question. With the up to nine months delay that you’re looking at right now, and you’ve talked about the potential to try to mitigate that delay given we’ve got some of the court cases over the next few months. How do you kind of assess your desire to mitigate the delay versus a desire to mitigate risk by waiting instead for the court decisions?

I mean, I think is principly a matter of mitigating the effects of the delay on schedule assuming we can do that in a very cost efficient way. And I’m optimistic that we can as work with our contractors in the permitting authorities to create more efficiency and timeliness of those processes of the events a last of weeks are very ecnouraging. And I’m optimistic as a result of those, but we need to maintain that and we need to be work with our contractors now to look for ways and means to keep schedule. The court actions as Steve said, we’ll play out as they play out, and I’m not going to speculate or predict of when or how those involve, we feel good about the cases that were put forward to the panel, viable to federal government anything in ourselves. And those decisions will flow in the normal course, but we’re not at this point attaching any schedule impacts as it relates to the FCA preceedings.

Great, understood. Thank you very much.

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

Hi, Becca, how are you?

Good thank you. Three minor questions. Kim, on the certain items that are listed in footnote one gas pipeline to negative $44 million to negative $20 in terminals positive 2018. Can you outline what those are? Why you’re looking – I’ll ask the second one, the legal settlement you’ve talked about, what was that for and can your mind for the amount?

The legal settleement was associated with the UPRr right away.

Okay.

And that was approximately $65 million. With respect to certain items – I can – why don’t we just do this offline?

Okay, we’ll do that.

I can talk to you about what each of those are, for example on thermals it’s probably associated with the sale of our interest and deep rock, which is a gain on that. Our natural gas it’s probably associated with the Eaglehawk settlement, which is a positive impact. But then you’re going to have contract amortization on a fair value of that charter rate and in terminals, which is going to potentially increase the gain, because that tax rate revenue that we record. We report as the certain item. So there’s a whole host of items which I’m happy to just do it in off line.

Okay, the last question is on the Southwest Colorado Production CO2 segment, the gross numbers are top and that numbers are down is there something unusually going on there?

Yes, absolute, gross numbers are up and better down, and so we had an expansion on one of our Southwest Colorado pipeline assets, and our partner in that expansion went non-consent, which means that we got the benefit of that of the higher interest ownership until pay out of that investment. Did I get that right? Okay.

This is on the volume from CO2, that right.

Yes, but she is talking about that why is the gross different from the net.

That’s from the production, they were non-consent on the pretty field.

On the field.

On the field not on the pipe.

Pipeline expansion. So partner went non-consent and then when the project paid out the partners interest returns.

Okay, gotcha. Thank you. That’s all I had.

Our next question is from Dave Winans with Prudential. Your line is open.

Good evening Dave.

Hey thanks guys. Just easy one, after the adjustments what’s the total budget capital spending budget at KML now?

In for 2017.

Q3 and Q4 are 214 and 267 roughly.

Thanks for taking one from a bondholder, appreciate it guys.

Do you get that Dave?

Yes, I got it. Thank you.

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

Sorry guys, just one last question. The the pension contribution in the quarter, how much was that in that like to sort of show you for the year?

Yes it’s $22 million and that’s all we expect to make this year.

Thank you.

At this time I’m showing no further questions.

Okay. Well, thank you all very much. And Yankee fans watch the game, I know the Astros friends will be. Thank you.

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