Kinder Morgan Inc - Class P (KMI) — Q1 2017 Earnings Call Transcript

Okay. Thank you, Carrie, and welcome to our first quarter analyst call. As always, before we begin, I would like to remind you that today’s earnings release and this call includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 and the Securities and Exchange Act of 1934, as well as certain non-GAAP financial measures. We encourage you to read our full disclosure on forward-looking statements and use of non-GAAP financial measures set forth at the end of our earnings release, as well as review our latest filings with the SEC for a list of risk factors that may cause actual results to differ materially from those in such forward-looking statements. I will kick this off by making a few remarks, then I will turn it over to Steve Kean, our CEO, and Kim Dang, our CFO, to give the operational and financial update, and then we will take any questions that you have. I want to quickly make two points. First of all, this quarter's good results in terms of EBITDA and DCF which Steve and Kim will discuss in detail, demonstrates once more the strength of the asset portfolio at KMI. We are able to generate substantial amounts of cash flow even in a challenging environment in our business. Sometimes, good solid financial and operational success, which is made possible only by a lot of hard work by the whole team, gets overlooked by some investors. But I would argue that it's one of the critical elements to the long-term economic health of any entity, and that includes Kinder Morgan. The second point I want to make is that Steve will update you in detail on this quarter's developments on our Elba and Trans Mountain projects, but let me say, we continue to make good progress on them, and on our goal of strengthening our balance sheet and thereby allowing us to return substantial value to our shareholders through some combination of dividend increases, share repurchases, additional attractive growth projects, and further debt reduction. Now, as I have said previously, we currently believe the best avenue for returning value is by an increased and well-covered dividend, and we expect to announce our revised dividend guidance for 2018 later this year. And with that, I will turn it over to Steve.

Thank you. I will provide some updates on our performance and key projects. We had a strong first quarter, with a DCF per share of $0.54, exceeding our initial guidance. We attribute this to timing and still anticipate staying on track for the full year. Regarding our Trans Mountain project, we have made significant progress on the project and are also working on either forming a joint venture with a partner or including it in an IPO. We reached a major milestone, increasing our cost estimate above the contractual cap of C$6.8 billion to C$7.42 billion. This increase allows our shippers the right to turn some capacity back to us. At the investor conference in January, we highlighted our confidence in the strong market demand for the project. Ultimately, all 708,000 barrels remained under long-term contracts, despite the increased tolls, which account for our return on the additional capital investment. Only 3% of the barrels were turned back, which were quickly reallocated to other customers during an open season. The contracts are typically for 15 to 20 years—mostly 20 years. This is a notable achievement considering these contracts were signed five years ago, during a $90 per barrel oil environment when the Canadian and U.S. dollars were at parity. Many factors have changed since then, including the conditions for many oilsands producers and project costs. Our shippers and commercial team worked diligently to place the barrels with both new and existing customers while managing those looking to assign our capacity. This illustrates that even with higher costs, the demand for the project remains robust, reaffirming its value based on the 2017 lineup of shipper needs and market conditions. Additionally, during the quarter, we received our environmental approval from British Columbia and now have agreements meeting the five conditions required for heavy oil pipelines crossing the province. These are strong regulatory and commercial developments. On the joint venture and IPO fronts, we have made progress on both tracks as we indicated we would in January, believing this approach will secure favorable financing terms. Our focus here is on value and project governance control. Both processes are progressing, and we plan to provide an update by the end of the quarter. Our plan assumes the JV partner will cover 50% of the capital without including our expected promote payment, which could enhance our debt-to-EBITDA target of 5.4. While there's interest in determining the project's value, we've refrained from setting a specific marker to maintain our negotiation position. I can affirm that this is an attractive project, aligning with our average 6.7X EBITDA multiple for the overall backlog. As previously announced, we finalized our Elba JV transaction in the first quarter at a value consistent with our 2017 plan, reflecting value beyond our capital spend, acknowledging the worth created in launching the project. On the backlog, I will be brief, this quarter it stands at $11.7 billion, $300 million lower than last quarter. As usual, there are multiple moving parts, small project additions and removals and some cost changes, but the main development is that we placed our Kinder Morgan export terminal into service, a liquids terminal dock and cross channel line project for one of our refinery customers on the Houston ship channel. We expect to update the backlog for the Trans Mountain outcome next quarter, so the project cost will now be approximately $5.7 billion, and the ownership level is expected to change. One more project update before moving to a few commercial highlights. On our Utopia pipeline project, our project team has done an excellent job of acquiring right of way and finding routing alternatives where necessary after an adverse court decision last year on eminent domain in one of the Ohio circuit courts. We are pleased with our progress and began the tree felling process in the first quarter. This joint venture project is under a long-term contract and is expected to be in service in January of next year. Now a few commercial market updates, starting with the gas segment. We experienced a slight increase in transmission volumes year-over-year, but gathering volumes were down. Starting with gathering, we generally see a leveling off of volumes in our key basins during the first quarter, though the comparison to the first quarter last year reflects the declines that took place throughout 2016. Generally, our volumes are in line with what is observed in the basins in which we operate, although we are performing a little better in our Bakken gas assets, with one exception being the Haynesville, where we are down on our KinderHawk asset, while the basin remains flat to slightly higher. This is due to the fact that our primary customer was not active in 2016. That is beginning to change, as we have added a new customer that is actively developing its acreage, so we expect some improvement there. Recall that our gas segment represents 55% of our segment. Earnings before DD&A and gathering, processing totals only 18% of that number. In terms of transmission volumes, we are up 1% year-over-year. The winter was weak; it was weak last year too, although we had a cold March in 2016. Power demand was down year-over-year. What I have read indicates that gas will still exceed coal's share of the power market again this year, but there was some gas-to-coal switching on our assets in the first quarter. Additionally, we saw higher renewables, including California hydropower, contributing to the year-over-year decline. Offsetting this were exports to Mexico, which were up 16% year-over-year on our systems and now averaging 2.8 BCF a day for the first quarter. It’s important to note that the majority of our margin here is secured by reservation fees, which are not affected by usage, but the volume information helps provide insight into the long-term value for the capacity. I also want to mention that LNG exports were up on our system year-over-year by half a BCF a day. We signed up an additional 400 a day of long-term firm transportation commitments in the quarter. Of that, 100 was existing but previously unsold capacity, bringing our total in the last three and a quarter years to 8.4 BCF of new sign-ups, of which 2.2 BCF is existing previously unsold capacity. We recently announced two developments related to the Permian. First, we announced a non-binding open season for a 1.7 BCF new build pipeline from the WAHA hub in West Texas to Agua Dulce in South Texas, our Gulf Coast express project. Last week, DCP announced its potential participation in that project as a partner and a shipper, and we are working with them over the next 90 days or so, to try to finalize that arrangement. DCP's assets in the Permian would provide good upstream connectivity and our Texas intrastate network would provide excellent downstream connectivity to Mexico, LNG at Corpus Christi, and utility and industrial markets along the Texas Gulf Coast. Gas production is growing in the Permian and increasingly, East Texas is becoming a premium market. We think the project makes a good deal of sense, but we are in the early days and we have not put it in the backlog. The second development related to the Permian is, we have a binding open season on our EPNG system for capacity to the WAHA. The open season package includes 150 a day of existing capacity, but it also reflects our ability to expand the system, by as much as 900 days more, to meet incremental demand. The expansions would be relatively inexpensive, and would again, demonstrate the value of having existing infrastructure that we can build off of at attractive returns. This project with a fee takeaway capacity at WAHA, including the potential Gulf Coast express pipeline in our Midstream business, and we continue to work both of those opportunities over the coming weeks. The overall summary on gas is that we continue to expect long-term benefit in the sector from increased LNG, Mexico exports, power and industrial demand, which should drive the demand from transportation storage infrastructure for the long term. Shifting to our products segment, refined products volumes are up 1% year-over-year, even though we experienced some weakness in Southeast U.S. markets. Crude and condensate transportation volumes are also up 1% year-over-year, notwithstanding declines year-over-year in the Bakken and Eagle Ford basins. KMCC in particular continues to show the benefit of its superior connectivity, both on the supply end and the Eagle Ford, as well as on the terminals in the Greater Houston area, and holding up very well in the face of declines experienced in the Eagle Ford as a whole on a year-over-year basis. In our terminals business, our liquids terminals utilization climbed to over 95%, as we continue to benefit from the strong positions we have built in several liquid hub locations. This team has been gradually migrating its business increasingly to the liquids part of the business. We are now at 80% of our segment earnings before DD&A coming from the liquids part of the business, and increasingly, our development activity is in the hub positions that we have built in Houston, Edmonton, New York, and Chicago over the years. We have kept our Jones Act vessels under charter on renewals that we have experienced. We had the discount to do that, but we expect to be slightly ahead of our plan on this business, and we currently have all of our vessels under charter. We continue to make good progress in our baseline terminal expansion at our Edmonton hub, and as I mentioned, we put our Kinder Morgan export terminal project in service on the Houston ship channel. In the CO2 business, we came in slightly ahead of plan for the quarter, with pricing offsetting lower crude production volumes. Also of note, we achieved record CO2 volumes during the first quarter. Our demand was up, but so were our third parties'. They had strong demand for CO2 off of our system. So again, overall, a strong quarter, with strong financial performance, continued progress on our project execution, and on our joint venture plans for our key projects. And with that, I will turn it over to Kim.

Good. Thanks, Steve. Today, we are announcing a dividend of $0.125 per share, which aligns with our budget. Let me highlight the key points of our performance, and then I will dive into the details. I will begin with the GAAP numbers and then discuss DCF. DCF is our primary method for evaluating our numbers and performance. Earnings per share attributable to common stockholders have increased by 50% this quarter. While it would be easy to credit ourselves for this increase, I believe it doesn’t accurately represent our performance. Adjusted earnings per share, which we included on the GAAP income statement after certain adjustments, is about $0.01. DCF per share, which is how we primarily assess our performance, declined by 1% or $18 million compared to the first quarter of 2016, entirely due to the sale of a 50% stake in SNG. Post-sale, DCF per share would remain steady. For the first quarter, the DCF per share of $0.54 exceeded our budget slightly, and for the full year, we are still on track to achieve $1.99 of DCF per share. On the balance sheet, we concluded the quarter at a debt-to-EBITDA ratio of 5.3 times, which is consistent with our end in 2016 and a notable improvement from 5.6 times in the first quarter of 2016. Now for the details, looking at the preliminary GAAP income statement, let me point out a couple of things to you there. You will see that revenues are up about 7% in the quarter, but the cost of sales is up by more, resulting in about a $121 million reduction in gross margin. Adjusting for certain items, gross margin would actually be down slightly more, would be down $146 million. The largest contributor to this decrease is the 50% sale of SNG. As a result of that sale, we no longer consolidate SNG's revenue and cost of sales, but report our 50% in net income further down the income statement as equity earnings. Now keep in mind also, that SNG did not have significant cost of sale. The impact of deconsolidating SNG was approximately $145 million reduction in gross margin for the quarter. Therefore, excluding the sale, gross margin would essentially be flat, which is consistent with how we would view our results. Net income available for the common shareholders is $401 million or $0.18 a share versus $276 million of income or $0.12 per share in the first quarter of 2016, resulting in $125 million or $0.06 per share increase or 45% and 50% respectively. Net income available to common shareholders before certain items for adjusted earnings was $371 million or $0.17 a share versus the adjusted number in 2016 of $402 million or $0.18 a share. Certain items in the first quarter of this year are income of $30 million, the largest of which is associated with proceeds we received from the sale of a bankruptcy claim on one of our natural gas pipeline. Certain items in the first quarter of 2016 were a net expense of $132, driven primarily by project write-offs and impairments. Now let's turn to the second page of financials, which shows our DCF for the quarter and the year and is reconciled to our GAAP numbers in the earnings release. As I said earlier, DCF is the primary financial measure on which we judge our performance. We generated total DCF for the quarter of $1.215 billion versus $1.233 billion for the comparable period in 2016, down $18 million or 1%. There are lots of moving parts, but the simple explanation I gave you earlier is true, which is after the sales of 50% interest in SNG that occurred in the third quarter of 2016, we would be flat. Segment EBITDA before certain items is down $90 million when you look up at the segment. That's primarily due to $113 million reduction in our natural gas segment. Of the $113 million reduction, $83 million is attributable to the SNG sale, and the natural gas decline is partially offset by a $26 million increase in our terminal segment, which is associated with expansion projects coming online in the marine division and in the Gulf Coast. G&A and interest are a benefit of $44 million in the quarter versus the first quarter of 2016, both largely as a result of the SNG transaction. In our adjustments to convert net income to DCF, we add back JV DD&A and subtract sustaining CapEx to more closely reflect the cash we expect to receive from our JV; because SNG is a JV in the first quarter of 2017 versus the fully consolidated asset in the first quarter of 2016, there is approximately a $17 million benefit between the two periods in our adjustment from net income to DCF to reflect the economic impact of the SNG JV. So a $90 million reduction in the segment. You add back the $17 million benefit to reflect the economic impact of the SNG transaction. The $44 million reduction between interest and G&A expense, and that gives you a net reduction of DCF of $29 million, which largely reconciles the change of $18 million in DCF. DCF per share was $0.54 versus $0.55 in the first quarter of the prior year, or down a penny, almost all of which is associated with the DCF changes I just walked you through. This $0.54 in DCF results in $935 million of excess distributable cash flow above our $0.125 dividend for the quarter. As I said earlier, for the quarter, we are ahead of budget, but for the full year, we expect to be on budget, largely as a result of some timing associated with sustaining CapEx, interest, and cash taxes that occur in the second, third, and fourth quarter. And with that, I will move to the balance sheet. On the balance sheet, as I said, we ended the quarter at 5.3 times net debt-to-EBITDA, consistent with where we ended 2016. Our budget for 2017 is that we would expect to end 2017 at 5.4 times debt-to-EBITDA. After the first quarter performance, we are still on track to achieve that. Remember, as Steve said, the budget or the current forecast, does not include any proceeds from a Trans Mountain promote, which we would expect to receive, and therefore, we would expect that our actual result will improve on the 5.4 times budget and forecast.

Okay. Carrie, we will now open the line for questions.

Good afternoon, guys. How are you doing?

Good.

All right. So can you guys tell me a little more about how you are thinking about the new Permian project particularly the gas takeaway pipe? You know, how the DCP deal came about? And if you are also willing, maybe project cost and any updates on the open season?

I will start with the open season, which is closing soon and is non-binding. The discussion with DCP began early, even before we announced the deal, and will continue from here. We jointly announced their participation because it provides us with upstream connectivity through their processing assets and pipelines in the Permian, as well as downstream connectivity to the markets that we connect with, including LNG and Mexico. There's enthusiasm for this opportunity, though it remains non-binding. Producers are increasingly exploring more routes out of the Permian, which can take time to develop. However, interest is there, and it will also inspire demand-side interest. On the demand side, we are a buyer of gas in Texas due to our numerous sales gas customers in the state. One approach we can take is to purchase the inlet to this pipeline, which could act as a bridge for some producer markets. Did I cover everything in your question?

Project cost?

Cost. Yeah, we haven't come out with cost yet. But I mean, it is a 1.7 BCF new build project. So you are looking at north of $1 billion.

Perfect. And then my next question is, we have seen a good bump in Eagle Ford rig count recently; can you maybe talk about how this is trending versus your original expectations and any chance for a positive revision related to this?

It's progressing as we expected with the price recovery we've observed. Generally, in the basin, we're witnessing a stabilization in volumes for both crude and gas this quarter, trending flat to slightly up, and likely finishing the year higher than present levels. That aligns with our planning for the year, and that's how we anticipate it unfolding. There may be slightly more activity than we had predicted at this stage. However, we still need to see how bringing volume online compares to just drilling as we move through the year.

Yeah. I think we build as we started. We ended the year kind of where we started with some declines early and then picking up. I think, some developments that have been encouraging, is the rig count has been up a good bit. The other thing is, and these are related, is that acreage has been changing hands down there. So it's going from people who were not actively developing to people who are actively developing, and that's a positive indication for the basin too.

And Steve, last real quick one for me, as I know you said end of Q2 for timing and then, still waiting on FID and arranging project financing, but any other color you want to give, maybe for what we should be waiting for?

No. Those are the key things really. I mean, we are running both of these processes simultaneously. And the reason for doing that of course, is to get to a value point that reflects a fully negotiated deal or a fully marketed process and it's not fully marketed or fully negotiated until it's done. And so, we are not there yet and so we haven't finalized yet.

Got it. Nice job on the quarter guys. Thank you.

Thank you.

Hi Brandon, how are you?

I am good. How are you Rich?

Good.

I have a couple of follow-up questions regarding Kristina's inquiries. First, about the Gulf Coast Express; Steve, you briefly mentioned some projects in El Paso related to the inlet side of that pipeline. Could you provide more details on what those projects entail? Are we looking at reversing compressor stations, adding compression, or both? Additionally, regarding the downstream aspect of that pipeline, it seems there is a mechanism to manage volumes along the Texas Gulf Coast, but could you share if any improvements are needed for that intrastate system, or if there is sufficient unutilized capacity available?

The open season on El Paso currently has a capacity of 150 a day that is available immediately, which will gradually increase as the contract expires. We can also add 900 of expansion capacity, with the first half requiring relatively low capital expenditures for back pressure valves and minor pipeline modifications. These adjustments can be made quickly under our existing blanket certificate, providing a valuable opportunity since the infrastructure is already in place. The second half of the expansion will necessitate additional compression, which is a bit more expensive but still manageable with minimal investment. Once we reach Texas, gas will flow primarily south and east towards Corpus and Mexico, and we are working on expanding that network with a recent crossover expansion that became operational in September of the previous year. The network provides options for expansion, which is not overly costly. However, if there's a substantial demand for gas volumes to Houston, we may need to consider additional expansions.

Yes, they go 1.7.

That will be a problem. We will be happy to have that problem, but

There is a lot of changing the direction of the flow. We are serving Mexico today with a fair amount of that market. Letting that volume stay allows us to pump some of it. Originally, these facilities were built to move gas from South Texas to Houston, and we have that capability now.

Another important point is that WAHA is a major hub, and there is considerable capacity becoming available from WAHA to Mexico. This is another valuable aspect of the EPNG projects.

I think once again, we have said over the years, how valuable it is to have the huge footprint that we have, particularly on the natural gas side, and this is just one more indicator of how valuable that is. The project is not done yet. The open season has concluded. But the fact of having all that pipe in the ground is of enormous advantage, when you start talking about expansions and extensions of your system.

Great color. And then I will probably just follow-on on that topic. Competitive environment, we have three pipes essentially, very similar projects announced in the same time period. So one, just what the competitive landscape looks like that, vis-à-vis producer interest? And then related, is there any chance of moving around the project, if there is demand and interest, say earlier 2019 or even late in 2018, is there something that can be done more quickly, in order to satisfy some residue gas takeaway issues?

It's an intrastate project, so it doesn't go through a federal process. If there's demand and it's urgent, we can act more swiftly. While it is competitive, I believe we have the best downstream connectivity, reaching all major markets, including rapidly growing ones, which is a significant advantage. Agua Dulce used to be just another spot in South Texas, but being connected to our system means you can access Mexico, Corpus Christi, or Houston, which is a strong position. We are currently working on selling the upstream aspect, and I think DCP fits well here. There are also other partners we can collaborate with to ensure gas can be delivered to WAHA, and the EPNG expansion aligns well with that. Overall, we believe we have a strong offering. Other competitors might claim the same, but when you consider both upstream and downstream, our offer stands out.

And one thing I would add Steve is, we are reducing interest from some of our customers in the intrastate network, actually wanting to reach back potentially all the way to WAHA. So again, I think that's something we offer in our project that our competitors don't.

Plus, we'd like to buy some of the gas.

All right. Perfect. Thank you very much guys.

Thank you, Brandon.

Hi Shneur. Good afternoon.

Good afternoon everyone. To start, I would like to follow up on some questions about the Permian Gulf Coast project. With DCP potentially involved, how close are you to reaching a commitment level that would allow you to confidently move forward? Additionally, regarding project returns, I understand the board has been focused on achieving mid-teens returns. Is that the target you need for this project to progress, or are you open to accepting a lower return hurdle due to the contracted nature of this opportunity?

It's too early to discuss that. We have a non-binding open season coming to a close, and while there is interest from shippers and producers, this situation is still developing as they evaluate takeaway capacity from the Permian alongside their own production. I believe we are still a way off from fully developing this project. We have a solid offering, and I am confident DCP can generate volumes for themselves while we can meet purchase requirements. There are many compelling aspects to this, but we are still quite some distance from moving forward. Regarding returns, we typically start with a target of 15% unlevered after-tax returns, and in projects developed from our network, we have been successful in achieving those returns. This project shares some similar characteristics when considering the downstream network and potential upstream on EPNG. Furthermore, when we have secured cash flows through long-term contracts with strong credits, we have advised our business unit leaders not to dismiss opportunities just because they offer slightly lower returns. Instead, we want them to bring these proposals to us for evaluation, taking into account the overall risk-adjusted basis. Therefore, our valuation approach is flexible and considers all relevant circumstances.

Okay. Pivoting to TMX for a moment, you have the federal B.C. approvals secured, but there is significant debate regarding TMX in the upcoming B.C. elections. I have two questions: first, what options might a new government in British Columbia have to influence the project? Second, are discussions with any joint venture partners potentially on hold until after the election results are in, or are those discussions still ongoing and unaffected by the elections?

I will address the last question first. There is no suspension of any process. We are moving forward on both processes. Regarding the B.C. election, we have received both federal and provincial approval, which includes the EA and environmental approval. This also encompasses reaching an agreement with British Columbia on the benefits of their five conditions, primarily aimed at providing advantages to B.C., along with risk reduction for marine and land responses. Additionally, this project offers many benefits to British Columbia that we believe are recognized and should be considered, particularly in creating jobs in B.C. There is economic development and advantages for the First Nations and communities along the route with whom we have mutual benefits agreements. We have established detailed plans and protections to mitigate any perceived risks from the project, and this is a federally sanctioned initiative. We are closely monitoring developments, and while the B.C. government can influence the project, it may be too early to discuss the specific impacts at this time. We believe we have strong momentum at both the federal and provincial levels, thanks to the efforts we've made in collaboration with those governments to address raised concerns and ensure that benefits are shared with the broader public. We feel confident that we have solid support from both levels of government.

Okay. And one final question; last quarter, you mentioned potential signs of improvement. The first quarter appears to have some momentum as well. However, you did not adjust your year-end leverage target. Are you observing these signs of improvement? Is there a possibility of exceeding your leverage targets or EBITDA targets by year-end? I was curious if you could share your observations regarding the developments in these areas.

Yeah, again, we are not changing our outlook and notwithstanding the strong first quarter performance, we are not changing our outlook for the full year. In terms of the debt-to-EBITDA metric changing, I think the main mover there is probably getting the financial arrangements in place for the Trans Mountain project. We are just a few weeks into the second quarter here, and I think there are some promising developments there. The rig count is one thing we have mentioned. Our Haynesville producer becoming more active on the gathering part of it. We are happy to be up 1% year-over-year on crude and condensate and refined products volumes. But it's just a little early for us to call anything different on our EBITDA at this point.

Great. Thank you very much guys. Appreciate the color.

Afternoon Ted.

Hey Rich. How are you doing?

Good.

Considering the joint venture and the announcement regarding Elba, can you share the terms you established for Elba? Please provide insight into how potential partners might evaluate investing in Trans Mountain.

I don't believe that's the case. These are very distinct projects. The return from Trans Mountain aligns with the average return of our backlog, which is approximately 6.7 times. Therefore, they are genuinely very different projects, and it's difficult to draw parallels. However, I can say that we were compensated for the work we did in developing the project at Elba, just as we did with Utopia, and we anticipate a similar outcome with Trans Mountain.

The construction processes for these projects vary significantly. Trans Mountain will require more time to complete compared to Elba, which is a self-contained site with an established EPC contract. In contrast, Trans Mountain involves multiple trucks operating over extensive distances. Therefore, these projects present distinct returns and risk profiles. I anticipate that investors and potential joint venture partners will consider these factors carefully. Consequently, it's not appropriate to compare Elba directly with Trans Mountain.

That's right. I would add, that of course what we have on both projects is very strong long-term contracts with creditworthy entities, and I think, we just can't overemphasize on Trans Mountain, the fact that we have all these shippers who were signed up for 708,000 barrels a day, almost all of them for 20 years, and that is a very important factor, just like we have signed up on Elba for that period.

Great. I know this was discussed extensively at Analyst Day, but I wanted to ask if you are open to walking away from the process or an IPO if you cannot agree on favorable terms with a joint venture partner. In case the election does not go as expected next month, would you consider self-building the entire project, or would you prefer to pursue the IPO process? I'm curious about your direction regarding this.

Yeah. I think that's not a decision we are confronting yet. We fully expect that the two-track process is going to produce successful results for us, so that's what we are basing our decision-making on right now.

Okay, fair enough. If I could ask one more smaller question: regarding the two Section 5 rate cases you are currently facing this year, what would be the annual revenue impact if the pipelines return to what we would consider a reasonable ROE, as the FERC assesses it?

We strongly believe it was inappropriate to start those proceedings because not all the facts concerning those assets were fully considered in the section five process. We are currently in discussions with our customers, and we did not anticipate anything more than a minimal impact on the margin for those assets.

Good afternoon, Jean Ann.

Hi, good afternoon. If you look at adding to your backlog. Should we think of the DCP JV as an indicator of broader interest than getting into the Permian in a bigger way? Or is it just opportunistic, since you already had existing gas assets? You had sort of continued to focus on building out existing basin?

No, we would like to expand our presence in the Permian. We have existing assets that serve the area, including EPNG and a line on the Texas intrastate, which is fully utilized and difficult to expand. Additionally, NGPL serves the Permian and transports gas north to Chicago, providing opportunities to leverage developments in that system.

Great. And then, I don't think that this is victory, but can you just give a sense of how much of your backlog is waiting for quorum to move forward?

I think, Tom correct me on this. We got orders on the projects that were time critical already, before the quorum disappeared early in the year. And so now, I think where we are is, we are not going to find the time critical issue, so long as they get quorum by midyear, thereabouts or even late 2017. So it's not constraining us right now, Jean Ann.

Okay. Great. That's all for me. Thanks.

Thanks. Most of my questions have been asked, but I had a couple of follow-up questions on TMX. Within the B.C. agreement that you signed earlier this month, I think you stipulated the June end decision timeline followed by a July 2nd announcement. Is that the absolute latest we will hear something, or can you announce something prior to that?

Yeah. That was really to set a date that was out there, kind of at the end of the timing thinking. So it was just a negotiated date, and it was put out there to be kind of at the end of the timing.

Okay. So we could hear something earlier than that?

Possible.

Okay. Secondly, within that agreement, is there any protection that you have from this potential change in political regime in the province?

Something in the agreement?

If there is a political change, does the agreement change in any way?

No, the agreement doesn't change. No, the agreement does not change.

Got you. Last but not least, just a clean-up question for me; what was the CO2 CapEx for the quarter?

$112 million.

Got it. Thank you. That's it for me.

Hey John. How are you doing?

Good Rich. Thanks. Just a couple of quick ones here; just on the real strong export volumes on Mexico this quarter, and what kind of growth rate is expected for the rest of the year, in terms of export volumes to Mexico?

Tom, do you have a feel for that?

That's a tough question. It really depends on when additional capacity comes online. I'm not sure I can provide a specific number. We should see an upward trend from this point, but it's going to be a gradual process. There is a significant increase ahead, and I believe it will continue to grow steadily.

Okay. And then, just on the dividend. I am wondering if there are any thoughts on whether to increase it significantly with slower growth or to increase it less but grow it quickly? Do you have any initial thoughts on the dividend policy?

We are planning to increase our efforts and achieve rapid growth. Just to clarify, we will have more information on this later in the year. We consistently emphasize that we believe we will have the capability to significantly raise the dividend. When that happens, we want to ensure that the dividend is well supported. Ideally, in a typical year, we aim to fund the equity part of our expansion capital expenditures from our cash flow, which would provide solid coverage for any dividend we pay. However, we have not made any detailed decisions yet. As we've stated, we will revisit this later this year and provide our outlook for 2018.

Okay, great. I have one more question about Trans Mountain. You might not be able to comment on this, but regarding the timing of the payment, I recall there was a discussion at Analyst Day about paying a significant portion of the amount upfront rather than over the construction process. Can you provide any additional details or insights on that?

That's still consistent with our expectation?

Which one, Steve?

The upfront, giving a significant portion of the proceeds upfront.

Paid upfront. All right. That's helpful. Thank you. That's it for me.

Thank you, John.

Good evening Darren.

Good afternoon Rich. Hope you and everybody is doing well. Steve, just a quick question for you on Gulf Coast Express; when we put all the pieces of the puzzle together, of the 1.7 that's being marketed, inclusive of the reside gas that DCP could commit, and we can all see what that is, and the options both upstream and downstream at the pipe that you talked about. Based on what you are marketing, how much total capacity do you think is necessary to commercialize the project? And then, as you mentioned, it makes a world of sense to be a buyer of that gas, especially if they can come back and capitalize on some regional opportunities, so how much capacity would you want to just leave open for that opportunity?

It's too early to say. If the demand is sufficient, you wouldn't need to fill the entire pipeline. Our purchase business exceeds 1 BCF a day, which includes the whole portfolio.

Probably 2.5.

2.5 BCF a day and Eagle Ford is declining. It would be a nice way to fill in for that at an attractive price, and the purchase part of the portfolio, the Texas intrastate. It's too early to determine what that mix will be.

Do you have an estimate of the necessary takeaway capacity when you consider the marketing of residue gas from the basin, especially in relation to high growth expectations, whether for your operations or those of third parties?

I mean, I think at least in some analysis we'd see the need for two additional pipes. So definitely enough to build this project.

Okay. Thank you.

Hi Jeremy. How are you?

Good. Good afternoon. Thanks. Going back to TMX for a second here, I was just wondering if you could remind us if you guys had kind of finalized whether or not the JV and IPO process, whether that would include existing assets, or is it just the project itself? Could you just walk us through your way of thinking there?

It is quite challenging, essentially impossible, to separate the expansion from the current Trans Mountain system. It is essentially an extension of that system, including some inactive reactivations and shared facilities at the terminals and dock. Therefore, our approach for selling this, whether through a joint venture or an IPO, will also include the existing system. In the case of the IPO, there might also be a broader offering of our Canadian assets.

Got you. Thanks. And just one more, as far as Gulf Express there, and congratulations on that project, where the open season there. Was just curious as far as the interplay between kind of new projects and kind of returning a dividend to a higher level in the interplay, because I assume, 2018 CapEx steps down somewhat from 2017 and that kind of helps you in the process of being able to lift the dividend. And so it's a great thing to win new projects, but then, you know, you see the interplay there, as far as the leverage is concerned. So just wondering if you could walk us through your thoughts there?

I think it relates back to what Rich mentioned earlier. We want to ensure that we have sufficient coverage for our dividend to continue funding the equity portion of our growth capital plan. Therefore, we will be considering all of this as we develop our guidance for the latter part of this year.

Got you. Great. Thank you.

Michael, how are you?

Good, thanks. Just two quick follow-ups on Trans Mountain, on the JV IPO. Just what is the latest in terms of timing? In terms of when you think you will have an announcement? And then second question, would FID come sort of concurrent with that, or is that running on some sort of separate track? Thanks.

The timing is this quarter, and we haven't been more specific than that Michael. We are running both processes simultaneously, and again, the point there is that we want to get ourselves to a fully negotiated JV side or fully marketed on the IPO side to kind of see what our value is. We would expect that the FID would come close in time with the conclusion of those processes.

Got it. Thank you.

Okay. Thank you very much, Carrie. Thanks for all of you participating in our call and we will talk later.