Welcome to the quarterly earnings conference call. At this time, all participants are in a listen-only mode until the question-and-answer session of today's conference. At that time, you may press star one on your phone to ask a question. I would like to inform all parties that today's conference is being recorded. If you have any objections, you may disconnect at this time. I would now like to turn the conference over to Mr. Rich Kinder, Executive Chairman of Kinder Morgan. Thank you. You may begin.
Okay. Thank you, Sheila, Welcome to our first quarter analyst call for both KMI and KML. Before we begin, as usual, I'd like to remind you that today's earnings releases by KMI and KML, and this call, includes forward-looking and financial outlook statements within the meaning of the Private Securities Litigation Reform Act of 1995, the Securities Exchange Act of 1934, and applicable Canadian provincial and territorial securities laws, as well as certain non-GAAP financial measures.
Before making any investment decision, 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, to review our latest filings with the SEC and Canadian provincial and territorial securities commissions 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 out of the way, let me make just a few comments before turning the call over to Steve. First of all, on a very positive note, our board today made some important personnel decisions I believe will benefit KMI for years to come. We promoted four really outstanding people.
Kim Dang to President of the company, Dax Sanders to Executive Vice President and Chief Strategy Officer of KMI, David Michels to Vice President and Chief Financial Officer, Anthony Ashley, currently VP and Treasurer, to Treasurer and VP of Investor Relations. I will remain Executive Chairman. Steve will remain CEO. We're very pleased with those. They're outstanding individuals, we look forward to many good years of performance. Let me talk a little bit about our results in a broad sense. As you can see from 2017 full-year results and from the results of the first quarter of 2018, which Kim will share with you today, and from our full-year 2018 budget and outlook, KMI continues to generate strong cash flow. We intend to use that cash in a fiscally responsible manner to benefit our shareholders.
In that regard, when you think about it, there are several potential uses of these funds. We can use them for expansion CapEx or selective acquisitions, either of which helps us grow the company. We can use the funds to pay dividends to our shareholders. We can buy in shares, or we can pay down our debt. In my judgment, any and all of these options create value for our shareholders. Speaking of dividends, consistent with our prior announcement, we are this quarter raising our dividend payable to our common shareholders by 60% from an annualized rate of $0.50 a share to $0.80 per share. I'm very pleased at our ability to reward our shareholders by returning this additional cash to them.
I would remind you that we continue to fund all of our capital expenditures with internally generated funds, and as Kim will describe, that we have bought back additional shares during the first quarter. Steve?
Thanks, Rich. I'm going to update you on KMI performance highlights and then turn it over to Kim, as usual, to take you through the financials. Following that, I will update you on KML and again turn it back to Kim, who's filling in for Dax Sanders on today's call, so that she can review KML's financial performance with you. Then we'll take your questions on both KMI and KML. Starting with KMI, we had a strong quarter at KMI with positive signs for full-year performance. KMI as a whole generated DCF per share of $0.56 for the quarter, an increase of about 4% year-over-year. Both natural gas and the CO2 segments were above plan and solidly up year-over-year, 6% and 7% respectively. We continued to execute well on our growth projects.
We placed $700 million worth of expansions into service during the quarter. We continued to find attractive new opportunities and added $900 million worth of projects to the backlog during the quarter. The vast majority of the backlog additions are in our natural gas segment. Turning to the natural gas segment, our transport volumes were up 10% year-over-year in the first quarter, and gas gathered and crude gathered volumes were up 1% and 3% respectively. The 10% increase in the transport volumes was on top of an 8% year-over-year increase that we had in the fourth quarter of last year. Two quarters in a row of strong year-over-year growth. On the gathering, there were pluses and minuses. We're up in the Haynesville on our gathered gas volumes and on our Hiland assets in the Bakken.
We're up on both gas and crude gathered volumes. Those are partially offset by lower gathered volumes in the Eagle Ford. We also continued to see strong pull on the demand side. Power was up 22% year-over-year on our systems. Mexico exports up 2%. A reminder, Kinder Morgan exports about 70% of the gas that is exported Mexico. On the volumes, we had a normal winter overall, with extremes early in January that drove all-time records on four of our large networks. Cold weather helps remind the market of the value of holding firm transportation and storage capacity. There's more going on here in the gas segment than a few cold winter days. Gas supply and demand is growing across the U.S.
Volumes are growing in the Permian, the Bakken, and the Haynesville, driving producer push activity, and growing LNG exports are creating demand pull. This elevates the value of our existing network and creates opportunity for new investment. A couple of data points to illustrate that. About 90% of our $900 million of backlog additions in the quarter were in the gas segment. A further illustration, we signed up about 1.2 Bcf of Permian capacity on our El Paso Natural Gas transmission lines. These are short-haul moves. The expansion capital required is very modest. For a little over $30 million and with an EBITDA multiple of less than 2x. This illustrates the value of having pipe in the ground while overall utilization of the network is climbing as a result of growing supply and demand, including export demand.
We made progress during the quarter signing up the remaining capacity on our 2 Bcf a day Gulf Coast Express project. 94% of the capacity is now spoken for under long-term reservation-based contracts. The last 6% is a long-term gas purchase by our Texas intrastates to serve our sales business in the state of Texas. That commitment is pending. We would expect to conclude it soon. Attention in the basin has now turned to the need for a second pipeline. Discussions are in early stages. In the CO2 segment, we benefited from both higher crude production and higher prices. Our largest field, SACROC, has performed above plan in the first quarter and is up 4% year-over-year.
We continue to see promising results out of the transition zone, which is an additional target area for us that could add 600 million-700 million barrels of original oil in place to the SACROC field. The production at our smaller fields, Katz, Goldsmith, and Tall Cotton, is up 18% year-over-year, with Tall Cotton by itself being up 58% year-over-year. On Tall Cotton, we have grown production there. Mechanical and operational issues have kept volumes below our expectations for that development. We're working on that. We'll be working on it in the coming months. We will want to be convinced that we have solutions before we commit capital to the phase 3 development effort there.
In our products segment, we saw refined products volumes increase about 0.5% year-over-year, which in contrast to the fourth quarter, is a little less than the 1.9% EIA estimate for the broader industry. We had strong deliveries in the fourth quarter of last year, particularly in December and particularly in Arizona, and that likely had a carryover impact on the first quarter of this year, meaning inventories built during December and therefore depressed draws or throughput on the pipeline. We're on plan for the quarter in the segment. Earnings before DD&A basis were up about 1% year-over-year. We also placed our Utopia pipeline in service in January of this year.
The terminal segment was down about 2% year-over-year, in part attributable to the impact of divestitures as John and the team continue to orient our business more toward hub positions and have gradually shed non-core positions. We're making good progress on our Baseline Terminal project in Edmonton, where we are on time and on budget as we bring tanks into service over the course of the year. There's one other topic I'll cover on KMI, and it's this. We've seen some nice emergence of some good tailwinds in the gas segment. Certainly observed those in the first quarter. We also saw a longer-term headwind emerge as FERC has initiated a notice of proposed rulemaking and other actions designed to flow through the benefit of tax law changes through pipeline rates.
Given the settlements and moratoria that we have in place, including one settlement we have pending before the commission right now, we do not expect to see an incremental negative impact in 2018 or 2019 to our outlook. As we said in the January call before the NOPR came out, we expect the impact of FERC's action to be mitigated and spread over time. That is still our expectation, and here's why. Only about a third of our interstate natural gas pipeline revenue is collected under max rate tariffs. We have negotiated rate arrangements in place, which even the commission acknowledges should not be disturbed, and we also sell a significant share of our capacity under discounted rate arrangements. Second, we have rate case moratoria in place on several of our systems, which inhibit the reopening of existing rates.
Third, rate cases under Section 4, and particularly under Section 5 of the Natural Gas Act, are prospective in effect, with impacts on the Section 4 cases being no earlier than 30 days or 5 months following the date of filing and on Section 5, prospective from a final order. In recent years, the most the commission has initiated on the Section 5 front is four in a year. Other years have been zero or one or two. That compares to over 130 regulated entities in the gas sector. Fourth, an observation. We believe the Form No. 501-G filings that we'll all be making will not be as useful as assumed by the commission in terms of determining so-called over-earnings separate and apart from the impact of tax law changes. We believe this for a number of reasons.
The NGs ignore the instructions, ignore important commission principles, including the NOPR's recognition of the status of negotiated arrangements. The form also uses an outdated ROE decision that is applied on a one-size-fits-all basis. We believe the forms will overstate matters and will have limited utility. We intend to use everything at our disposal to mitigate the negative effects of the actions and to spread their effects over time. We have quantified the impact of the tax rate change in isolation and believe that the incremental impact of that change, to our outlook, is about $100 million a year if fully implemented, which again, we would expect would be delayed. It's incremental, meaning that's on top of what we already assumed. We had already taken this into account on SFPP in our outlook and in our pending settlement on SNG, for example.
This does not include other negative impacts from new rate proceedings, which we believe are too uncertain, both in amount and timing, to quantify at this point. One final point here, this is not about rate making, but it's about fundamental justice and reasonableness, which is something we will urge the commission to take into account as it considers how to exercise its discretion to pursue Section 5 cases. For over 30 years now, the commission has methodically created a competitive market in the interstate natural gas pipeline industry. That policy has been steadily implemented through Republican and Democratic administrations. It has delivered enormous benefits to producers and consumers. Pipelines are open access. Shippers can sell the capacity they hold in competition with the pipeline who provides it, and pipelines can build new pipelines in competition with incumbents. Pipelines are not analogous to traditional regulated utilities.
The traditional regulatory compact balances exclusive franchised service territories, which are insulated from competition on the one hand, with rate regulation on the other hand, that caps rates but enables a reasonable return on capital. Pipelines do not have protected franchises. Most rates are set in a competitive market, and many systems under-recover a regulated cost of service with no effective opportunity to raise rates, given the competitive market environment that the commission policy has created. It's neither just nor reasonable to ignore the industry's competitive structure and selectively apply the other half of the regulatory compact rate regulation to some systems without enabling other systems that under-recover to recover their cost of service. We expect to continue pressing these arguments, as we expect other people in the industry will as well, with the commission as they work through what we expect to be a time-consuming implementation process.
With that, I'll turn it over to our President, Kim Dang.
Thanks, Steve. Today we're declaring a dividend of $0.20 per share. As Rich said, that's a 60% increase over last quarter, consistent with our budget as well as the plan we laid out for everyone last July. Based on our current stock price, the $0.20 per quarter or $0.80 to annualize results in a very attractive dividend yield of over 5% with significant coverage. As Steve said, we had an outstanding first quarter, well above our budget and nicely above last year. For the full year, we expect to meet or exceed our DCF and EBITDA budget. First, today, let me start with the GAAP numbers, then I'll move to DCF, which is the way that we look at and judge our performance.
Net income attributable to common stockholders for the quarter was $485 million or $0.22 a share, which is an increase of $84 million in total or $0.04 per share, respectively, with both increases being over a 20% increase versus the first quarter of last year. As you can see from looking at the income tax expense line item on our GAAP income statement, almost all of this increase results from lower income tax expense, primarily due to the reduction in the tax rate associated with the new tax law. If you adjust for certain items, which are for this quarter, the first quarter of 2018, an immaterial $4 million expense, but were a benefit of about $30 million in the first quarter of 2017.
The change in income tax expense accounts for a little less than 60% of the change as opposed to the entire change, with the remaining change generated by stronger operating contributions. Adjusted earnings, which excludes these certain item changes, are up $118 million or 29%. Adjusted earnings per share of $0.22 is the same as the unadjusted number because, as I mentioned, certain items for the quarter had a minimal impact. DCF per share, which is the primary way we judge our performance, is $0.56 per share, up $0.02, which is 4% higher versus the first quarter of 2017. Total DCF of almost $1.25 billion is up approximately $32 million or 3%. The nice increase in DCF was driven primarily by greater contributions from natural gas and CO2, partially offset by higher sustaining CapEx, cash taxes, and the impact of the KML IPO.
DCF per share was up 4% versus the 3% on total DCF due to 21 million fewer shares outstanding. We repurchased approximately $250 million worth of shares in the fourth quarter of last year and approximately $250 million in the first quarter of this year. Overall, the segments were up 4% or $78 million, with natural gas up 6%, contributing $63 million or over 80% of the improvement. Natural gas benefited from nice performance on the Texas intrastates and TGP driven by winter weather. On Hiland, driven by increased drilling activity. On NGPL, as a result of lower interest expense. EPNG, due to greater capacity sales, primarily driven by the Permian. On FGT, due to lower taxes.
The CO2 segment was up $15 million or 7%, driven by a 5% increase in net oil volume, primarily at SACROC and Tall Cotton, as Steve mentioned, as well as increases in oil and NGL prices. Non-controlling interest is higher by approximately $13 million due to the IPO of our Canadian assets last May. Cash taxes were $16 million higher than the first quarter of 2017, but are actually lower than our budget for the quarter and expected to be significantly lower than our budget for the full year. Sustaining CapEx was approximately $10 million higher in the first quarter of 2018 versus 2017. As you may remember, our 2018 budget for sustaining CapEx was higher than our 2017 actuals. I went through that variance explanation at our analyst conference.
For the first quarter, we're actually running a favorable variance to budget, that's going to be timing for the full year. The segments are up $78 million, less the $26 million combined increase in sustaining CapEx and cash taxes, and the $13 million increase in non-controlling interest. That totals a $39 million increase in DCF versus the $32 million increase shown on the page. There are obviously more moving pieces, but that gives you a big picture of what's going on. We're off to a great start this year, and as I previously mentioned, we expect DCF for the full year to meet or exceed our budget, driven by better performance from our natural gas and CO2 segments. Lower cash taxes, offset by higher interest expense due to higher LIBOR rates.
Certain items for the quarter were an expense of $4 million, as I mentioned, immaterial in total. There were, however, a few offsetting items. There's a $37 million expense primarily related to an SFPP rate case reserve, which relates to prior periods. The 2018 impact of this is included in our results for the first quarter and taken into account in our forecast for the full year. There's a $40 million expense related to hedge ineffectiveness on our oil hedges, primarily related to an increase in the Mid-Cush differential. These two expenses were largely offset by two tax benefit items. First, the release of a tax reserve on a sales and use tax. Secondly, the impact of tax reform on a couple of our joint ventures. Our expansion CapEx budget for the year was $2.2 billion.
Our current forecast is $2.3 billion as we've identified some incremental projects that meet our return requirements. Let me once again remind you that the $2.2 billion does not include any KML CapEx. With that, let me move to the balance sheet. There is one change in the balance sheet this quarter that I want to point out. You'll see a new caption between liabilities and shareholders' equity entitled redeemable non-controlling interest, which for GAAP purposes is considered mezzanine equity. Due to a change in the accounting rules, starting in 2018, an amount related to our Elba JV, which we previously classified as a long-term liability, is now reflected as mezzanine equity.
This is an item that we've disclosed in our financials, for those of you who enjoy reading our 10-K and 10-Qs, since we entered into the Elba JV, which reflects the fact that in certain limited circumstances, which we do not expect to occur, our JV partner has the right to redeem his capital account. The Elba project is well underway with the first units expected to be delivered in the third quarter of this year. We ended the quarter at 5.1 times debt to EBITDA, flat to last quarter. In this calculation, we use net debt, including 50% of the KML preferred shares in the numerator, which is consistent with how the rating agencies treat those shares. Currently, we expect to end the year at or below our budget of 5.1 times debt to EBITDA. Net debt ended the quarter at $36.7 billion.
That's an increase of $331 million in the quarter, which I will reconcile for you. Of the $331 million, about $100 million is associated with increased debt in Canada, and $231 million is associated with KMI standalone. We had DCF in the quarter, as I mentioned earlier, $1.247 billion. We had a little less than $650 million of expansion capital and contributions to equity investments. That's actually about $645 million, includes expenditures at Trans Mountain because it's consolidated. If you excluded Trans Mountain, the capital spending is a little bit over $510 million. We had dividends of $277 million. We made share repurchases of $250 million, then we had working capital and other items of a little over $400 million. On the working capital and other items, accrued interest was a use of cash of about $195 million as we make interest payments.
Our significant interest payments are made in the first and third quarters, the accrual that's in DCF is a constant throughout the year. We also had a use of cash associated with accrued liabilities of about $125 million, that's because we make bonus payments in the first quarter, also there are significant property tax payments made in the first quarter. We also had a use of cash associated with the DCF being reflected being slightly greater than the distributions that we received from our equity investment. With that, I'll turn it back to Steve.
Okay. We're going to switch to KML. Last week, we announced that KML has had a decision point on the Trans Mountain expansion project. We announced the suspension of non-essential spending and that under current conditions, we would not put additional KML capital at risk. We also said there is no read-through from this in terms of our willingness to invest in Canada. We have invested in Canada, British Columbia as well as Alberta, we expect to continue investing. As we said then, it's become clear this particular investment may be untenable for a private party to undertake. The events of the last 10 days have confirmed those views. We pointed out there are significant differences between governments. Those differences are outside of our ability to resolve.
We are continuing our stakeholder discussions between now and May 31, and we're looking for a way forward on the project. All of that is the same as what we said on the call last week. Nothing new there. Discussions are underway, and as the Prime Minister said on Sunday, we're not going to undertake those discussions in public. We do not intend to provide additional updates on the status of those until we reach a sufficiently definitive agreement or the discussions have terminated. Again, not much update, but discussions have commenced. With that, I'll turn it over to Kim to talk about the financial performance of KML during the quarter.
Thanks, Steve. Let me preface my comments as Dax has in prior quarters with the caveat that while we are offering quarter-over-quarter comparisons, those comparisons are of limited value given that we're reporting a quarter where KML was owned by the public versus a quarter where it was wholly owned by KMI. During those periods prior to the IPO, there were significant shareholder loans in place that generated FX, most of which is unrealized, and intercompany interest with KMI that are not reflective of the true earnings power of KML. We would ask you to focus on the actual results to 2018 and how they compare to our published budget. Quarter-over-quarter will be more starting in the third and fourth quarters of this year when we have comparable quarters all post-IPO. Moving to the results.
Today, the KML board declared a dividend for the third quarter of 16 and a quarter cents per restricted voting share, or $0.65 annualized, which is consistent with our budget and previous guidance. Earnings per restricted voting share for the first quarter of 2018 are $0.10, derived from $44 million of net income, which is down approximately $2 million or 5% versus the same quarter in 2017. In the first quarter of 2017, we recognized a foreign exchange gain associated with the intercompany loans. These loans were settled at the time of the IPO, that gain does not recur in 2018. Adjusted earnings, which includes certain items, the most significant of which is the FX gain I just mentioned, were approximately $44 million compared to approximately $40 million for the same quarter in 2017.
This increase is largely associated with a decrease in interest expense given the extinguishment of the intercompany loans and increased AEDC associated with the spending on the Trans Mountain expansion project. Total DCF for the quarter is approximately $77 million, which is down $6.4 million from the comparable period in 2017, but favorable to our budget. That DCF provides coverage approximately $5.5 million and reflects a DCF payout ratio of approximately 76%. Looking at the components of the DCF variance, segment EBITDA before certain items is up $6.8 million compared to Q1 2017, with the pipeline segment up $7.3 million and the terminal segment down very slightly. The pipeline segment was higher primarily due to the AEDC associated with the spending on the project.
The terminal segment was lower due to the termination of a contract in Q1 2017, for which we received a net termination benefit, and lower volumes at our Vancouver Wharves terminal, offset by the Baseline Terminal coming into service. On the Baseline Terminal project, we placed six of the 12 tanks into service during the quarter. The first four tanks went into service on schedule in January, which we talked to you about at our January investor conference. The next two, which were scheduled to be placed into service the first couple of weeks of June, were actually placed in service early in mid-March and the beginning of April. G&A is higher by about $2.4 million, primarily associated with higher costs of being a public company. Lower interest expense and higher preferred share dividends, they largely offset each other.
Sustaining CapEx was favorable about $3.4 million compared to 2017, but we expect sustaining CapEx to be slightly favorable to the budget for the year. Cash taxes increased by $6.5 million to $6.6 million over the same quarter in 2018. In 2017, we were not required to make estimated cash tax payments, but do need to make them in Q1 of 2018. Now moving on to the specifics for the full year. Currently, we expect EBITDA and DCF excluding AEDC for the full year to be on plan. AEDC and capitalized interest will be highly dependent upon what happens with the project. With that, I'll move to the balance sheet. As you can see there, we did draw on the facility during the quarter for approximately $100 million, but we still ended the quarter with a net cash position of $110 million.
If you add 50% of our preferred equity to our net debt balance, which is, again, the way the rating agencies generally look at it, our net debt position at March 31st was approximately $165 million. For the quarter, net debt increased by approximately $129 million from December 31st. Let me reconcile that for you. DCF was $77 million. Expansion CapEx was $167 million. Growth dividends were $58 million. The DRIP, the dividend reinvestment program, generated proceeds of $15 million, and then working capital and other items were a slight positive. Finally, just a couple of things on expansion capital. On Baseline Terminal, we've now spent approximately $304 million of our share of the $398 million on the project, so about $94 million left to spend in 2018.
On Trans Mountain, we've now spent about $1.1 billion as of 3/31, with approximately $550 million of that spent by KMI in periods prior to the IPO and about spent by KML since the consummation of the IPO. With that, I'll turn it back to Steve.
Okay. Sheila, we're ready to take questions on KMI and KML.
Thank you. To ask a question, please press star one. Our first question comes from Jeremy Tonet with J.P. Morgan. Your line is open.
Hey, Jeremy, how are you?
Good. Good afternoon. Thanks. Just wanted to see, with regards to the FERC matters, if you had talked to the commissioners there. Do you have any sense that there could be any kind of reconsideration of what they've done here? It seems like some of the comments, maybe they didn't fully expect some of the actions that happened in the marketplace, given what they did during open market hours.
Yeah, look, I think even in public testimony statements as recently as yesterday, there was a recognition, I think, that a lot of comments are going to have to be reviewed and a lot of input is going to have to be taken in in order to make the right decisions here. So we're encouraged by that. We're obviously reaching out, and our industry is reaching out in every way that it can to make sure that our views and our facts are known to the commission as they're figuring out how to proceed here. It's extremely important, I think, for the commission to take into account the results, the benefits, but also the other implications of a long-standing policy of creating competition and competitive markets in interstate pipeline transmission. They succeeded. They've succeeded in that.
That is a fundamentally different environment than, say, a traditional regulated utility, and that needs to be adequately taken into account as they think about how to use and exercise their discretion. So we're encouraged by their openness to the input, and we intend to give them plenty of it. I didn't mean that disrespectfully.
Thanks. Just a couple of quick follow-ups and just wanted to see, when you were talking about moratorium, was that the FERC is prohibited from reopening where you have a moratorium? Am I correct in understanding what you said there? Also, just as far as how this applies to liquids pipelines, I was wondering if you might be able to expand a little bit there on the refined product side.
Yeah. The settlements really are applying to the gas pipeline side of the house. We're in ongoing rate case on SFPP. It's been going on for a very long time. Talking specifically about gas, settlements don't bind subsequent commissions, but they are generally honored, and there's good language in FERC orders about settlements and rate moratoria that are in place where they tend to respect them. The parties sit around and negotiate an outcome, and they do so in good faith, the commission, along with the customers and the pipeline. Typically, those settlements will bind the private parties, if you will, to their terms, but can't legally bind the commission. Again, the practice has been for the commission to honor those.
Great. Thanks. Just one last one, if I could. With regards to the Permian pipeline, the second one that you were talking about there, that's interesting to hear. Just wondering if you could talk about the competitive dynamic as far as pursuing this project, if you look to bring that to the same market or a different path, and just how you think, I guess, Waha basis moves over time here, and if that could benefit KMI in the interim, as it seems like even GCX isn't going to be online for a while here, and the basis has really widened out. I don't know if there's other smaller brownfield things that you could do in the interim to take advantage of that.
Well, look, you put your finger right on the fundamentals, I don't want you to leave the call being all too interested in what we said there. This is very early kind of discussions, I think it is the view in that market that a second pipe really is needed. I think it's clear that certain producers with significant production coming online have been holding, if you will, holding commitments back in order to help underwrite a second pipeline. It does look likely that something will be built.
We have the same advantages that we talked about when we talked about Gulf Coast Express, which is there's some, with the right makeup of partners, there's good upstream connectivity, we have great downstream connectivity to get that gas to the markets that are really booming right now, which is along the Texas Gulf Coast, both for Mexico exports as well as power and petchem demand and LNG. We think that we have some advantages in that, it's in the very early Don't get too interested just yet, I'd say. I think you're right. The fundamentals are strong, I think they support a second pipeline getting built. The gas is growing rapidly in the Permian, it is a low cost, if not a negative cost, to producers who are primarily aiming at NGLs and crude out there.
Finding a way to deal with the gas and not have to flare it is very important, people, I think, shippers are rapidly catching up to that and thinking about ways to relieve those constraints. In the meantime, the smaller bottleneck, de-bottlenecking, that's kind of what we're doing on the EPNG investments that I mentioned. We're looking at some things on NGPL as well. We will continue to look for those, as well as take away from EPNG as these supplies are hunting markets.
That's all very helpful. Thank you for taking my question.
The next question comes from Shneur Gershuni with UBS. Your line is open.
Hi, Shneur.
Good afternoon, everyone. Congratulations to everyone on the promotion.
Thanks.
Just a quick follow-up to Jeremy Tonet's question there. Could GCX be brought into service sooner, given all the demand that everyone's talking about?
Bob?
No, I think we're certainly trying to do everything we can to get it online as soon as possible. I think our fourth quarter of 2019 to the Gulf Coast is really the most realistic timeline.
Okay, great. Just a couple of questions. Of course, starting at a high level. I think we've all beat the FERC to death at this point. I was just wondering if you can talk about returns on capital deployment. As you think about your business over the last couple of years and you've upped your CapEx a little bit and you're looking at another project. When one looks at capital returns, are you achieving the returns that you've outlined in the past? Has the erosion in commodity prices of CO2 kind of masked some of those returns? I was wondering if you can talk about that a little bit.
Yeah. No, good question. We have done well on our project execution, Kim actually went through that, and you'll see a look back from 2015 through 2017 on capital projects and how they came out as a multiple of the year two EBITDA, meaning once the project is fully up and running. We've done very well, and we've done similar backward looks at our gathering and processing investments, et cetera. The new investments that we talk about this quarter are at about six times rate. So I think we're doing quite well there. You're right. There's been some deterioration. If you look over that whole period, 2015 to 2017, there's been deterioration in the underlying CO2 business because of lower commodity prices primarily. There have also been some contract roll-offs.
There's also been some JVs and asset divestitures that we've undertaken in order to improve the balance sheet. We've retired over $5.8 billion of debt since late in 2015, and we've improved our multiple from 5.6 to 5.1 times. As Rich Kinder said, we're using our cash, deploying it effectively in projects, and we're using our cash to de-lever, as well as return value to shareholders, and I think we've done that effectively over the last two to three years.
Great. Two quick follow-ups. One, you were just talking about the return of capital and so forth. You bought back some shares during the quarter. At the same time, you've upped your CapEx estimate for this year. How should we think about your discretionary cash flow that you outlined, I believe it was about $565 million at the Analyst Day, in terms of its ability to continue buying back stock? I guess pair that with the fact that you're suggesting that you can beat your guidance or projected plan for this year.
Well, if you look at the situation, of course, we were very clear that we had that number that we showed you, the $550-plus million of free cash flow after funding all of our capital expenditures for the year and obviously after paying the dividend. Since that time, we have bought back $250 million worth of stock. You could deduct that. Then as the capital moves around, the total expansion CapEx, which as Kim Dang said, now rounds to 2.3 instead of 2.2, you would also deduct that. Our projections would show we will still, after everything we've done, all the capital we have in the plan and all the stock buybacks we've done thus far, we are still nicely positive in terms of actual cash generated after we pay for all these things internally.
In terms of how to use that cash, it's the same things we talked about at the beginning of the year and Rich Kinder talked about earlier in the call, which is we'll look at what's the best use, whether it's an incremental project or the return of additional value to shareholders through a share buyback or further de-levering. It's nice to be in this position.
Great. One final question. During, I think it was the last quarter or two quarters ago, there was a lot of talk about Double H, and the potential for NGL repurposing. At the same time, the production level for crude in the Bakken has continued to grow, and other takeaway pipelines have been filling towards capacity. Do you see a trend of improving crude production and heading towards Double H, and therefore there's no real need to really think about an NGL repurposing? Or is that still on the table?
Yeah, we don't have put together an NGL repurposing project. Discussions around that pipeline have turned toward how do we get more of that production into Double H, and we've been able to successfully buy and attract some volumes, including truck volumes, over to Double H. That's been a positive. There's still a bit of capacity overhang to work through in the Bakken. The production there has been very promising from a gas, NGL, and oil standpoint. Prospects, I'd say, are improving there.
Great. Thank you very much, guys.
The next question comes from Danilo Juvane with BMO Capital Markets. Your line is open.
Good afternoon.
Good afternoon. Congrats to everyone with emotions today. My first question is on the buybacks. You've done $500 million thus far. You have $1.5 billion still left. Are you done for this year, or should we expect you to continue to buy back more shares this year?
Yeah, as we just went through the free cash flow, we have a little bit of free cash flow still remaining. I think at this point, we're going to look and probably wait a little bit to see what the capital projects look like and see if there are any more of those. Depending on what happens with CapEx, there may be the opportunity to buy back more shares and/or pay down debt.
Thanks for that. Given where the stock is sort of trading right now, have your thoughts at all evolved on maybe deploying that elsewhere perhaps just paying down debt instead of buying back shares?
I think we will look at that on an opportunistic basis. I think the important thing here, and I hate to keep beating the same drum, but we're in a unique and very positive situation in funding all of our expansion CapEx with internally generated funds, paying the dividend, and still having sizable excess cash to use, we're going to consider that very carefully. As I said in my opening remarks, we want to be fiscally responsible in how we handle that capital. We will look at it, just amplifying what Kim said, we will look at it on an ongoing basis to figure out what makes the most sense. Look, we shouldn't skate around this. We've improved our balance sheet considerably. As Steve said, we've paid down well over $5 billion worth of debt.
We are now, as Kim says, we targeted 5.1 as a debt-to-EBITDA ratio at the end of 2018. We will meet or beat that, we think. We're moving in the right direction, but we would like to get it lower, obviously. That's a weighing process between de-levering and buying back shares.
Thanks, Rich. Rich, moving on to the backlog. I noticed in the release that you're now deploying organic growth ex Trans Mountain at 6 times. I know that previously we said that that number was 7.5 times and 6.7, I think. Is this improvement that you've made a function of you just being able to deploy capital more efficiently? Can we get some color into that dynamic?
Look, we look at every project individually, we want to get the highest return we can get that the market will pay. We'll look at the underlying risk on a project. We'll demand a higher return for it, but we'll get as much as the market will bear. I think the numbers you were talking about is more like 6.5 and 6.7 times, and it's kind of toggled around that. I wouldn't read anything different into the fact that this particular slate of projects that we're talking about is at 6 times. We're applying the same criteria we've been applying for several years now, a couple of years now, which is elevated return criteria well above any reasonable calculated cost of capital. We'll try to get absolutely as much as we can from the market.
Long as we are clearing by a substantial margin our cost of capital, we'll deploy that capital if it's the best use of that cash. We targeted a 15% unlevered after-tax return. We don't reject anything. We come in and discuss it, right? Some things that are better than a 15% unlevered after-tax return have too much risk associated with them, and they don't make the cut. Some things that are below 15% but have de-risked with long-term reservation-based contracts, we relaxed that 15%. We have continued on that path.
Thanks, Rich. Last one from me. What was the CO2 CapEx spend from the quarter?
$91 million.
Thank you.
The next question comes from Jean Ann Salisbury with Bernstein. Your line is open.
Hi, Jean Ann.
Hi. Good afternoon. I had a few questions about the Permian, one more on gas. On your existing gas pipelines out of the Permian, is there any room at all for expansion through compression, or is this it?
Tom?
Yeah, certainly some of the projects that we're doing on EPNG are those types of projects, very minor CapEx, just squeezing out additional capacity from our existing network. In Texas intrastates, I think we're largely really sold out, that has a lot to do with why we're involved in GCX. I would say those are really the two main areas, we've also found some opportunities off in NGPL. Some of that has been executed on, we're pursuing a bit more as well. I think all of those are very low-cost, high-return opportunities, we're pursuing every bit of those that we can.
The other thing we've seen is, it's been in small chunks so far, people are looking for any outlet out of the Permian, including Even Cheyenne Plains and WIC has seen some of the effects from the growth in the Permian Basin. That's not expansions. That's existing capacity. Filling up all the nooks and crannies coming out of the Permian to get to a different market.
Okay. Can you put any numbers at all, I guess, in terms of TPFD on how much more you can actually get out on El Paso and DDL? Too early to say?
That's hard to say. As you can tell from the map, it's a network out there, it depends just on what installations you can put where, whether it's back pressure regulators, which are very cheap, or compression, which is more expensive, and other connections and things like that. It's a network.
Sure. Thank you. I believe you and Watco operate or maybe used to operate a rail terminal in the Permian. Can you confirm if you still have that and what the crude by rail loading capacity available is if you do?
Not any longer. I think, generally speaking, in the Permian, there's not significant current crude by rail unit train capacity. There's manifest cargo capability, but not unit train capability. Is that right?
Okay. Thank you. Then one last one. I think you touched on this when you discussed the hedges, you've hedged your EOR production with WTI, do you have crude transport out of the Permian, or do you mostly receive a Midland price for your barrels and are exposed to that spread?
We do have transport out of the Permian, including with our Wink Pipeline assets, which takes a significant amount of our production to Western Refining in El Paso. We also, as part of our hedging program, we hedge quality and locational differentials. We've hedged for 2018. We're at about 68%, I think, of Mid-Cush hedged.
71.
71% of Mid-Cush hedged, we're continuing to add to that position as we go through 2018.
Great. That's very helpful. That's all for me. Thank you.
The next question comes from Darren Horowitz with Raymond James. Your line is open.
Hey, Darren, how you doing?
Hey, Rich. Good afternoon, and again, congrats to everybody on the promotions. Steve, my first question is on CO2. Do you guys have a rough estimate of the cost or return profile per barrel in order to monetize those incremental transition zone barrels versus some smaller fields? Because I know you talked, and you guys have put out some slides on the after-tax internal rate of return. But on a risk-adjusted basis, I'm just wondering how to think about return on investment going forward with how you allocate those additional dollars.
I'll start and Jesse will finish. One of the great things about the transition zone development is that it is sitting below the area that we are already developing with CO2. When we develop a project, we go hit the traditional CO2 flood zone and exploit that. With a little bit of deepening, and sometimes we can even use existing wellheads or well bores for that deepening, we can access transition zone barrels. What happens there is we get both. We get it from our traditional harvest area, as well as we pick up incremental barrels from the transition zone in those places where we've found it, and so far, we've found it in a number of places. I think roughly speaking, it's like 28%, 72%, 70/30 of traditional CO2 flood recovery with another 30% transition zone coming from that deepening.
Is that about right, Jesse?
That's right.
That makes it very capital efficient.
Right.
That's the bottom line.
How much of that, if any, is built into the $1.6 billion growth backlog forecast from 2018 out to 2022? I know that you guys have already experimented on what five transition zone wells in the budget this year is too. Is that correct?
I think you're thinking in terms of development.
Development dollars.
Yeah.
There's very little of that is associated with the backlog. This is very early, and we're still delineating the field, it's very little of that $1.7 billion.
I'll just point out that in CO2 in particular and also in gathering and processing, that capital moves around to chase the best opportunities.
Steve, as this evolves theoretically more focused on the transition zone going forward based on those rate returns that you guys have discussed, how do you expect the aggregate segment return on investment to evolve over the forecast period within which you're going to spend that $1.6 billion?
You're beyond any update that we've tried to do, Darren. We're not there yet.
Okay. If I could, just one final question for me on Elba. What's the expected timing of the liquefaction capacity between initial in-service in the third quarter this year and when you guys reach 10 liquefaction units by the middle of 2019? How do we think about the timing of the remaining capital spend over those four quarters?
You want to speak?
I mean, you have the timeline correct. The first unit will be online in the third quarter, and it's approximately 30 to 45 days sequentially from that point. That gets us into the late second quarter, early third quarter of 2019.
As you probably recall, the return or the economics on the liquefaction development are heavily weighted to unit one. Unit one, we expect will be coming on Unit 3 will not get in in the third quarter, Unit 1 is expected to get in in the third quarter.
Okay. Thank you.
The next question comes from Keith Stanley with Wolfe Research. Your line is open.
Good afternoon, Keith.
Hi. Good afternoon. Just wanted to clarify on the growth backlog, the $900 million addition in Q1, that does not include Gulf Coast Express that was already in the backlog. Is that correct?
You are correct. We put that in in the fourth quarter update that we shared in January.
Okay.
This is on top of that.
Could you just give color on maybe one or two of the largest additions to the backlog in terms of the projects and the timing of them coming into service? I think some of the other opportunities you've mentioned around the Permian are a little smaller in terms of capital.
Right. Tom, do you have a rough New York and GNP is about $500 million. Then the interstate projects across, I guess, really three different regions is another $300.
Okay.
That's the last number. Again, of the 900, 820 is natural gas. That's the overwhelming majority of it is in the natural gas segment.
Got it. Okay. One, just on Trans Mountain. One of the principles you laid out pretty clearly is the need for certainty to construct across British Columbia. When you think about some of the discussions on potential financial arrangements with the federal government, can that help address that criteria, that one criteria, or do you also need some type of specific action or change separate from financial support to give you more confidence you can build across B.C.?
Yeah, they're really two separate things. There needs to be a way. Most of the project and most of the investment is in British Columbia, where the government is in opposition to the project and has looked for and found ways to incrementally regulate it. That is an issue that, in our view, needs to be resolved or addressed in order to be able to successfully construct in the province. We think of them as two separate but related things.
Thank you.
The next question comes from Dennis Coleman with Bank of America. Your line is open.
Good afternoon, Dennis.
Good afternoon to you, Rich. Thanks. My congrats to everyone there on the promotions. A couple from me, please. Steve, back to the FERC issue, I guess. One comment I want to just dig a little bit into. You talked about this being a time-consuming process sort of at the end of your statement there. My recollection is the commission when they were making these decisions sort of were thinking that these would be a fairly quick process. I want to say they talked about it being done as early as the fall of 2018. I wonder maybe if you can just talk about the differences or compare those two views and maybe give some scale of how you think about the timing, how long this will take.
Right. The FERC has laid out a specific schedule in three or four tranches of filing of these 501-G forms. Right? That's pretty well-defined, but that's just the beginning. There's a lot more, and for reasons I said earlier, these forms, I think, are going to be less informative, particularly on the issue of over-earning than people are expecting because there are some assumptions built into those instructions that we believe conflict with, frankly, what we think a commission is ultimately likely to do. There's a process of information gathering that's on a very firm timeframe.
There's still the whole NOPR itself, which is a proposed rule, and a separate but related notice of inquiry, which is an earlier step even in the process that has to be worked out, and that's the process within which we'll be filing comments and making our case known and seeking some modifications to the rule or the proposed rule. Then there are the processes themselves, rate proceedings themselves, and those are expensive. They're time-consuming, and that's why we have some confidence around the idea that this is going to ultimately play itself out over time.
Okay. The idea of 130 pipelines all getting done by the fall is not realistic. In terms of the 501G filings themselves, they have to be filed I thought it was a 30-day process. It seems like you're indicating that there's some variance there.
No, there's a phased in, they've listed specific entities and what wave they're in. There are specific dates for filing a 501G for each individual regulated system.
Okay.
Four separate waves.
Okay. Thanks for that. One quick question on the leverage number. You say, Kim, that you'll be 5.1 times or potentially below, and I want to just clarify that a little bit if I can in terms of that's on the existing budget, that doesn't include any assumptions about Trans Mountain going forward or not. I think when you made the announcement a couple weeks ago, there was some indication that it would be 0.2 lower.
Right.
If that doesn't proceed.
Right. What we've assumed in the 5.1 times or better is a similar but updated assumption that we had in our budget, which is we spend at a reduced rate through May, and the spending would ramp up. If Trans Mountain were terminated, we think longer term, not this year, but longer term because you would have incremental spending in future years. If you pursued the project longer term, there would be a 20 basis point reduction versus what we would have thought if the project went forward in 2019.
Okay. Thanks for that. Just one last one for me. In the KML release, there was some discussion about lower rail loadings in the quarter from Canada. I wonder if you just might talk a little bit about that one. Why this? That surprised me a little bit.
It's rail service related. The service has been very abysmal in that area. Imperial has been negotiating directly with the CN and the CP for improvements in that. We have seen an uptick as the quarter progressed, but it was down significantly throughout the quarter. We hope that that will improve as we go forward here.
It's not because the barrels don't want to move.
They don't.
Right. That's why it surprised me. Any of that weather related or any particular reason, or just poor service?
It was all poor service related. Remember, that facility is all 100% take or pay related, it didn't have as big a financial impact, we would like to see the barrels to move.
Okay. That's it for me. Thanks, everyone.
The next question comes from Robert Catellier with CIBC Capital Markets. Your line is open.
Good afternoon, Robert.
Good afternoon, everyone. Hi. I just wanted to ask a couple of questions on KML. First of all, on Trans Mountain. Want to respect the fact that you're not negotiating publicly. I want to inquire about the possibility that any financial agreement with either Alberta or the federal government might result in shareholder dilution or any less exposure to the Trans Mountain project upside. Is this primarily a risk mitigation discussion similar to a surety bond, where shareholder upside might remain intact?
Yeah, Robert. Look, I appreciate the interest in additional color. We're interested too, there's really nothing more to add there. We have outlined two principles, I'm just going to restate them. There has to be a way to build through BC, there has to be a way to protect our shareholders. We are in discussions, those are the principles that we will be looking to preserve.
Okay. You haven't taken anything off the table I gather then? Any possibility?
We didn't say that. We just said we're in negotiations.
Yeah. Okay. You've answered most of my other operating questions, I'll just ask the one on the promotions. Congratulations to Dax and everyone else. I'm just curious, Dax obviously will continue his KML responsibilities. As far as I can tell, the press release was silent about David Michels. I'm wondering if he's going to continue his KML responsibilities as well.
Right now, the IR responsibilities for KML were under me. Now they'll be transitioned to Anthony Ashley, who's our Treasurer currently, and is today promoted from that to Treasurer and Vice President of Investor Relations.
Okay. Just finally, are these changes, the timings are just coincidental with the news on Trans Mountain, or is there any read through there?
No, there's no read through.
No.
No read through at all. Robert, I want to confirm you're correct. Dax will continue as Chief Financial Officer of KML.
Yeah. Okay. Congratulations. Thanks, guys.
The next question comes from Robert Kwan with RBC Capital Markets. Your line is open.
Robert, how are you doing?
Good. How are you doing?
Good.
Just wanted to ask on the Canadian M&A potential. I'm wondering first, do you need resolution on Trans Mountain before you really look in earnest on the M&A front? Then when you decide to get at it, can you just talk about the different types of assets you might pursue? Would they have to be similar to what KML has right now? Would they have to be similar to what KMI has, or could you potentially get into a new platform for kind of the entire enterprise?
Yeah. Robert, on the first part of that, we are in a period of considerable uncertainty, obviously, depending on how this comes out on the overall project. We've closely defined that period, in part because it creates a lot of uncertainty for our investors. We've closely defined it, and we've stated what we're looking for. There's no question it's uncertain and therefore makes it difficult to evaluate M&A activity. However, once we get to a point of clarity, the kinds of assets that we've always expressed an interest in in KML, that is Western Canadian midstream assets, would still be what we would be looking at and looking for. It's not a large group of players there.
There are some very capable players with good midstream assets. As you know, we have limited debt on this entity, and so it is something that we would want to look at. I just think realistically, you've got to let things settle out on the process that we're undergoing right now first.
Understood. I guess, Steve, you were talking about players versus specific assets, I guess I'm also wondering, if I can recall within the agreement between KMI and KML, KMI actually had the right to pursue corporate or publicly traded opportunities. Can you talk about whether that was more theoretical and that the intention absolutely is for publicly traded entities based in Western Canada to be within KML, or how should we think about that?
Yeah. KML is the entity through which we would be investing in Western Canadian midstream assets of the type that we already have, already own, and know how to operate, which would include other things that KMI owns and operates. Similar types of assets and operations. We've been very broad about that. The intent is, and was, that KML would be the vehicle to invest in those opportunities in Western Canada.
Got it. If I could just finish with the terminal side. Q1 was a little bit weaker. You talked about the rail movements, which sounds like from others, that's improved. I'm just wondering, are you still holding the 2018 terminals guidance despite the shortfall in Q1, how do you think you pick up the rest then as you head through the rest of the year?
Yeah, I think you're asking specifically about terminals on KML.
Yeah.
I think, our expectation is we'll come in in line with.
Yes. The big decrease was at Vancouver Wharves, which was down $3.5 million, and it was broken down by sulfur, which was one less vessel. We think that will catch up. We had force majeure on copper. We think that will catch up. The only one that may not catch up is the agri volume. That's going to depend on the railroads.
Okay. Does that catch up to run rate and then exceed it to make up for Q1? Is that what you?
To meet budget, yes.
Right.
Okay. That's great. Thank you.
The next question comes from Brian Zarahn with Mizuho. Your line is open.
Good afternoon, Brian.
Hey, Rich. You're circling back on your 2018 outlook to meet or beat your guidance of $2.05 per share on DCF. Just to review, your expectation is the gas and CO2 segments to outperform. Taxes should be lower, which more than offsets higher interest expense. Is that the right way to summarize your outlook?
If we beat, yes, those items would more than offset the interest expense.
Okay. On your guidance on a per share basis, how much of the potential upside is from the buyback?
We had the buyback factored into the budget.
Okay. On interest expense, can you just remind us on floating rate exposure and updates on the impact with LIBOR being above your budget?
Right. The forecast that I just gave you, our guidance for the year to meet or beat our EBITDA and DCF, factors in the LIBOR curve as of the end of last week. That's got a current LIBOR curve in there. Our exposure with respect to floating rates is about 30% of our debt is floating, and it's about $100 million of exposure for a full year impact of 100 basis points. You would have to have the 100 basis point increase starting January 1, and going throughout the full year to get to the $100 million.
Just shifting back to Trans Mountain, understanding that you're in negotiations on the expansion. In a scenario, hopefully unlikely, that the existing pipeline volumes are curtailed by a government, how should we think about the impacts of that potential outcome and any mitigants that KML has?
Are you talking about the proposed Alberta legislation?
Correct.
Yeah. Look, there's a lot of back and forth going on, and it's in a political realm, and it's not something that I feel particularly qualified to gauge for you. I think that what Alberta is saying You know what? I'm not even going to try to interpret it.
Yeah.
I think there's going to be some back and forth here, this is part of why we're seeking clarity. Okay.
Appreciate that. My last question is going back to FERC, shifting to the liquids pipeline side. It's not for about three years from now, looking at the new escalator taking effect in July of 2021, any initial thoughts on potential exposure to a lower indexation?
All that we've seen is probably what you've seen, Brian, which is that the commission deferred action on the tax issues for pipelines that are under index rates to that later date when they're going to be evaluating index overall. That's really all we know at this point as well.
Thanks you .
The next question comes from Ted Durbin with Goldman Sachs. Your line is open.
Good afternoon, Ted.
Yeah. Hey, how's it going? Just one question for me. If we look at the FERC again, assume that the process that they've laid out sticks with this Form No. 501-G, I guess, can you help us out? I realize you're in the process of filing all your Form No. 2s and working through them, The headline number on maybe some of your larger pipelines where you don't have a rate moratorium like Tennessee or EPNG. What sort of ROE are you going to be showing when you file your 2017 numbers?
Look, we do have moratorium in Tennessee.
Okay.
EPNG is subject to a rate case that's been going on for quite some time, and with fundamental underlying rate issues that still have not been resolved, which again, I think points to, Ted, the point that we're making, which is there's an awful lot to sort through before you can see the final and full impact implemented from what FERC is doing, looking at the tax flow through, but also taking the rest of the cost of service into account. It makes it hard to do quickly. I think that's the main point, and there'll be a lot of moving parts in those discussions and a lot of arguments brought to bear on it.
We don't have a number to quote you in terms of what returns are going to show in for Form 2s, but we're working on the Form 2 filings, and we'll make them in a timely fashion.
Okay. That's it for me. Thank you.
The next question comes from Becca Followill with US Capital Advisors. Your line is open.
Good afternoon, Becca.
Good afternoon. Back on 501-Gs. We've taken a look at them and agree that they're not really indicative of reality, given that they don't take into account negotiated rates. Any thoughts on commenting on the NOPR and trying to get some changes on that form, or do you think that's set in stone?
The filing is due on the 25th, right? I haven't seen our comments, but we'll be covering a lot of ground in there, I think I can assure you. The main thing, though, we'll be making the point that you just made, Becca, which is if they don't make these forms conform to reality, they're going to be of limited usefulness. Even then, it's hard to know how you can apply things like a one-size-fits-all ROE from a 2010 litigated rate case and just apply that to everybody. That's not the way things work when you're setting a cost of equity for a system. I think the 501-Gs are going to create more fog than light.
We'd agree. Then second, you may have already commented, but on Gulf Coast Express, any comments on potentially twinning that system? If you were to twin the timing to if you were to double it, could you accelerate that and do some of that along as you construct the first phase?
I don't think you could look for much synergy in construction there. Those are limited even when you set out to do it that way. There's some savings, but it's not as much as you would think. The other real consideration there is this gas may want to hit a different part of the Texas coast, and so that would take it out of that corridor.
Super. Thank you.
We are showing no further questions at this time.
Okay. Well, thank you very much for joining us this afternoon, and have a good evening.
This does conclude today's conference. Thank you for participating. You may disconnect at this time.