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. 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, and welcome to our Q1 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 and Exchange Act of 1934 and applicable Canadian provincial and territorial securities laws as well as certain non GAAP financial measures. Before making any investment 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 and 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 4 really outstanding people, Kim Dang to President of the company, Dax Sanders to Executive Vice President and Chief Strategy Officer of KMI, David Michaels to Vice President and Chief Financial Officer and Anthony Ashley, currently VP and Treasurer to Treasurer and VP of Investor Relations. I will remain Executive Chairman and Steve will remain CEO. But we're very pleased with those.
They're outstanding individuals and we look forward to many good years of performance. Now let me talk about 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 Q1 of 'eighteen, which Ken will share with you today, and from our full year 2018 budget and outlook, KMI continues to generate strong cash flow and 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. And 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.
And 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 brought back additional shares during the Q1.
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 continue to execute well on our growth projects. We placed $700,000,000 worth of expansions in the service during the quarter and we continue to find attractive new opportunities and added $900,000,000 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 is on top of an 8% year over year increase that we had in the Q4 of last year. So 2 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 Highland assets in the Bakken, we're up on both gas and crude gathered volumes and those are partially offset by lower gathered volumes in the Eagle Ford. We also continue to see strong pull on the demand side.
Power was up 22% year over year on our systems. Mexico exports up 2%. And a reminder, Kinder Morgan exports about 70% of the gas that is exported to Mexico. So on the volumes, we had a normal winter overall with extremes early in January that drove all time records on 4 of our large networks. Cold weather helps remind the market of the value of holding firm transportation and storage capacity.
But 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 investments.
A couple of data points to illustrate that. About 90% of our $900,000,000 of backlog additions in the quarter were in the GAAP 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 and the expansion capital is required is very modest for a little over $30,000,000 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 and we would expect to conclude it soon. Attention to the basin has now turned to the need for a second pipeline and 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 Q1 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 600,000,000 to 700,000,000 barrels of original oil in place to the Sacrock 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, but mechanical and operational issues have kept volumes below our expectations for that development.
We're working on that and we'll be working on it in the coming months and we will want to be convinced that we have solutions before we commit further capital or commit capital to the Phase 3 development effort there. In our product segment, we saw refined products volumes increase about 0.5 percent year over year, which in contrast to the Q4 is a little less than the 1.9% EIA estimate for the broader industry. We had strong deliveries in the Q4 of last year, particularly in December and particularly in Arizona. And that likely had a carryover impact on the Q1 of this year, meaning inventories built during December and therefore depressed draws or throughput on the pipeline. We were on plan for the quarter in the segment earnings before DD and A basis and we're 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 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 as this. We've seen some nice emergence of some good tailwinds in the gas segment, certainly observed those in the Q1. But 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 moratorium 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 'nineteen to our outlook. And as we said in the January call before the MOPR 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.
2nd, we have rate case moratorium in place on several of our systems, which inhibit the reopening of existing rates. 3rd, rate cases under Sections 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 perspective from a final order. In recent years, the most the commission has initiated on the Section 5 front is 4 in a year, other years have been 0 or 1 or 2. That compares to over 130 regulated entities in the gas sector. 4th, an observation.
We believe the 501 gs filings that we'll all be making will not be as useful as assumed by the commission in terms of determining so called over earning separate and apart from the impact of tax law changes. We believe this for a number of reasons. The 501s 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 is about to our outlook is about $100,000,000 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.
And one final point here, and 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 franchise 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 jouge 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. Now with that, I'll turn it over to our President, Kim Dank. Thanks, Steve. Okay.
Today, we're declaring a dividend
of $0.20 per share. As Rick 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 annualized results in a very attractive dividend yield of over 5% with significant coverage. As Steve said, we had an outstanding Q1 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 and 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 $485,000,000 or $0.22 a share, which is an increase of $84,000,000 in total or $0.04 per share, respectively, with both increases being over a 20% increase versus the Q1 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 change the new tax law. But if you adjust for certain items, which are for this quarter, the Q1 of 2018, an immaterial $4,000,000 expense, but were a benefit of about $30,000,000 in the Q1 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 $118,000,000 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 $56 per share, up $0.02 which is 4% higher versus the Q1 of 2017. Total DCF of almost $1,250,000,000 is up approximately $32,000,000 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 21,000,000 fewer shares outstanding. We repurchased approximately $250,000,000 worth of shares in the Q4 of last year and approximately $250,000,000 in the Q1 of this year. Overall, the segments were up 4% or $78,000,000 with natural gas up 6% contributing $63,000,000 or over 80% of the improvement. Natural gas benefited from nice performance on the Texas interest base in S and G, driven by winter weather on Highland, driven by increased drilling activity on NGPL as a result of lower interest expense EP and G due to greater capacity sales, primarily driven by the Permian and on FTT due to lower taxes. The CO2 segment was up $15,000,000 or 7%, driven by a 5% increase in net oil volume, primarily at Sacrock and Tall Cotton, as Steve mentioned, as well as increases in oil and NGL prices.
Non controlling interest is higher by approximately $13,000,000 due to the IPO of our Canadian assets last May. Cash taxes were $16,000,000 higher than the Q1 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 $10,000,000 higher in the Q1 of 2018 versus 2017. As you may remember, our 2018 budget for sustaining CapEx was higher than our 2017 actuals, and I went through that variance explanation at our analyst conference. For the Q1, we're actually running a favorable variance to budget, but that's going to be timing for the full year.
So the segments are up 78,000,000 dollars less the $26,000,000 combined increase in sustaining CapEx and cash taxes and the $13,000,000 increase in non controlling interest. That totals a $39,000,000 increase in DCF versus the $32,000,000 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 segment, lower cash taxes, offset by higher interest expense due to higher LIBOR rates.
Certain items for the quarter were an expense of 4,000,000 dollars so as I mentioned immaterial in total. There were however a few offsetting items. There's a $37,000,000 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 Q1 and taken into account in our forecast for the full year. There were $40,000,000 expense related to hedge and effectiveness on our oral hedges, primarily related to an increase in the Mid Cush differential.
And these two expenses were largely offset by 2 tax benefit items. 1st, the release of the tax reserve on a sales and use tax and secondly, the impact of tax reform on a couple of our joint ventures. Our expansion CapEx budget for the year was 2.2 dollars Our current forecast is $2,300,000,000 as we've identified some incremental projects that meet our return requirements. Let me once again remind you that the $2,200,000,000 does not include any KML CapEx. With that, let me move to the balance sheet.
There is one change in the balance sheet 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 disclosed in our financials for those of you who enjoy reading our 10 ks and 10 Qs since we entered into the held a 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 its capital account. The Elba project is well underway with the first units expected to be delivered in the Q3 of this year.
We ended the quarter at 5.1x debt to EBITDA, flat to last quarter. In this calculation, we used net debt, including 50% of the KML preferred shares in the denominator actually 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 $36,700,000,000 That's an increase of $331,000,000 in the quarter, which I will reconcile for you. Of the $331,000,000 about $100,000,000 is associated with increased debt in Canada and $231,000,000 is associated with KMI standalone.
We had DCF in the quarter, as I mentioned earlier, dollars 1,247,000,000 dollars We had a little less than $650,000,000 of expansion capital and contributions to equity investments. Now that $600,000,000 it's actually about $645,000,000 includes expenditures at Trans Mountain because it's consolidated. If you excluded Trans Mountain, the capital spending is a little bit over $510,000,000 We had dividends of $277,000,000 We made share repurchases of $250,000,000 And then we had working capital and other items of a little over $400,000,000 On the working capital and other items, accrued interest was a use of cash of about $195,000,000 as we make interest payments. Our significant interest payments are made in the 1st and third quarters, but 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 $125,000,000 and that's because we make bonus payments in the Q1 and also there's significant property tax payments made in the Q1.
And then we also had a use of cash associated with our DCF, the DCF being reflected being slightly greater than the distributions that we received from our equity investments. And so with that, I'll turn it back to Steve.
Okay. Now 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, and we expect to continue investing. But as we said then, it's become clear this particular investment may be untenable for a private party to undertake. The events of 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. However, discussions are underway. And as the Prime Minister said on Sunday, we're not going to undertake those discussions in public and 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. So 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. Therefore, we would ask you to focus on the actual results to 2018 and how they compare to our published budget. Quarter over quarter will mean more starting in the 3rd and 4th quarters of this year when we have comparable quarters all post IPO.
Now moving to the results. Today, the KML Board declared a dividend for the 3rd quarter of $0.1625 per restricted voting share or $0.65 annualized, which is consistent with our budget and previous guidance. Earnings per restricted voting share for the Q1 of 2018 or 0 point $0 derived from $44,000,000 of net income, which is down approximately $2,000,000 or 5% versus the same quarter in 2017. In the Q1 of 2017, we recognized a foreign exchange gain associated with the intercompany loans. These loans were settled at the time of the IPO and therefore 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 $44,000,000 compared to approximately $40,000,000 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 77,000,000 which is down $6,400,000 from the comparable period in 2017, but favorable to our budget. That DCF provides coverage of approximately $5,500,000 and reflects the DCF payout ratio of approximately 76%. Looking at the components of the DCF variance, segment EBITDA before certain items is up $6,800,000 compared to the Q1 2017, with the pipeline segment up $7,300,000 and the terminals segment down very slightly.
The Pipeline segment was higher primarily due to the AEDC associated with the spending on the project. The Terminals 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 Wharf terminal, offset by the Baseline terminal coming into service. On the Baseline terminal project, we placed 6 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 2, which were scheduled to be placed into service the 1st couple of weeks of June, were actually placed in service early in mid March and the beginning of April.
G and A is higher by about $2,400,000 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 $3,400,000 compared to 2017, but we expect sustaining CapEx to be slightly favorable to the budget for the year. Cash taxes increased by $6,500,000 to $6,600,000 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 on 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 $100,000,000 but we still ended the quarter with a net cash position of $110,000,000 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 31 was approximately 165,000,000 dollars For the quarter, net debt increased by approximately $129,000,000 from December 31.
And so let me reconcile that for you. DCF was $77,000,000 expansion CapEx was 167,000,000 dollars Gross dividends were $58,000,000 The DRIP, the dividend reinvestment program generated proceeds of 15,000,000 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 $304,000,000 of our share of the $398,000,000 on the project, so about $94,000,000 left to spend in 2018. On Trans Mountain, we've now spent about $1,100,000,000 as of threethirty 1, with approximately 5 $50,000,000 of that spent by KMI in periods prior to the IPO and the balance 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. Our first question comes from Jeremy Tonet with JPMorgan. Your line is open.
Hey, Jeremy. How are you? Good. Good afternoon. Thanks.
Just want to see with regards to the FERC matters, if you had talked to the commissioners there. And 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.
Yes. 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. And 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. And it's really I mean, 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. But 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. And 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 the moratorium, was that the FERC is prohibited from reopening where you have a moratorium? Am I correct in understanding what you said there? And also, just as far as how this applies to liquid to pipelines, I was wondering if you might be able to expand a little bit there on the refined product side?
Yes. So 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. And on the gas, 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 moratoriums or 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. And typically, those settlements are typically those settlements will bind the private parties, if you will, to their terms, but can't legally bind the commission. But again, the practice has been for the commission out of those.
Great. Thanks. And then just one last one, if I could, with regards to the Permian pipeline. The second one that you're 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 different paths 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 kind of widened out.
So I don't know 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. But 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, but I think it is the view in that market that a second pipe really is needed. And 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. So 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 is some and with the right makeup partners, there is good upstream connectivity and 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. And so we think we've got that we have some advantages in that, but it's in the very early stages. So don't get too interested just yet, I'd say. But I think you're right. The fundamentals are strong and I think they support a second pipeline getting built.
The gas is growing rapidly in the Permian and it is a low cost, if not a negative cost to producers who are primarily aiming at NGLs and crude out there. So finding a way to deal with the gas and not have to flare it is very important. And people, I think, are beginning to shippers are beginning to are rapidly catching up to that and thinking about ways to relieve those constraints. In the meantime, the smaller bottleneck debottlenecking, 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.
And we will continue to look for those as well as take away from EP and G as these markets 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. Hi, good afternoon, everyone, and congratulations to everyone on the promotion. Just a quick follow-up to Jeremy's question there. Could GCX be brought into service sooner given all the demand that everyone is talking about? Tom?
No, I think, I mean, we're certainly trying to do everything we can to get it online as soon as possible. But I think our Q4 of 'nineteen to the Gulf Coast is really the most realistic timeline.
Okay, great. Just a couple of questions. 1st, 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 sort of think about your business over the last couple of years and kind of 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 kind of outlined in the past? Has the erosion in commodity prices at CO2 kind of masked some of those returns? I was wondering if you can sort of
talk about that a little bit.
Yes. No, good question.
We have done well on our project execution, and 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 2 EBITDA, meaning once the project is fully up and running. And we've done very well and we've done similar backward looks at our gathering and processing investments, etcetera, the new investments that we talk about this quarter at about 6x rate. And so I think we're doing quite well there. And 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. So we've retired over $5,800,000,000 of debt since late in 2015 and we've improved our multiple from 5.6 to 5.1x. So we're as Rich said, we're using our cash, deploying it effectively in projects and we're using our cash to delever as well as return value to shareholders. And I think we've done that effectively over the last 2 to 3 years.
Great. And kind of 2 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 $565,000,000 at the Analyst Day in terms of its ability to continue buying back stock. And I guess, compare 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're very clear that we had that number that we showed you, the 550 plus 1,000,000 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 $250,000,000 worth of stock. And so you could deduct that. And then as the capital moves around, the total expansion CapEx, which as Kim said, now rounds the $2,300,000 instead of $2,200,000 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.
And so
in terms of how to use that cash, it's the same things we talked about at the beginning of the year and Rich 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 delevering. And it's nice to be in this position.
Great. And one final question. During, I think it was the last quarter or 2 quarters ago, there was a lot of talk about HH and the potential for NGL repurposing. But 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 HH and therefore there's no real need to really think about an NGL repurposing or
is it
still on the table?
Yes. We don't have put together an NGL repurposing project, but the second part of what you said is also true, which is production is rising in the Bakken. And so some of our 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 HH. And so that's been a positive. There's still a bit of capacity overhang to work through in the Bakken.
But the production there has been very promising from a gas NGL and oil standpoint. So prospects I'd say are improving there.
Great. Thank you very much, guys.
The next question comes from Danilo Juvani with BMO Capital Markets. Your line is open.
Good afternoon.
Good afternoon. Congrats to everyone who received the promotion today. My first question is on the buybacks. You've done $500,000,000 thus far. You have when the math doing still less, Are you done for this year?
Or should we expect you to continue to buy back more shares down this year?
Yes. I mean, as we just went through the free cash 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. But depending on what happens with CapEx, there may be the opportunity to buy back more shares and or pay down debt.
Thanks for that. And even with
the stock dislocating right now, have your thoughts at all evolved on maybe redeploying that elsewhere, perhaps just paying down debt instead of buying back shares?
Well, I think we will look at that on an opportunistic basis. I think the important thing here and it keeps beating the same drum, but we are 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. And we're going to consider that very carefully. And as I said in my opening remarks, we want to be fiscally responsible in how we handle that capital. So 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.
So look, we've improved we shouldn't skate around this. We've improved our balance sheet considerably. As Steve said, we've paid down well over $5,000,000,000 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.
And so we're moving in the right direction, but we would like to get it lower obviously. And so that's a way process between delevering and buying back shares.
Thanks for the color, Rich. Moving on to the backlog. I noticed in the release that you're now deploying organic growth ex Trans Mountain at 6x. Know that previously we said that, that number was 7.5x and 6.7x, 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? Yes. Look, we
look at every project individually. And so we want to get the highest return we can get that the market will pay. And so we will look at the underlying risk of the project. We'll demand a higher return for it, but we'll get as much as the market will bear. We have I think the numbers you were talking about is more like 6.5x and 6.7x and it's kind of toggled around that.
I wouldn't read anything different into the fact that this slate of particular slate of projects that we're talking about is that 6x. We're applying the same criteria we've been applying for several years now, which a couple of years now, which is elevated return criteria well above any reasonable calculated cost of capital. And we'll try to get absolutely as much as we can from the market. And so 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've targeted a 15% unlevered after tax return, but 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 derisked with long term reservation based contracts, we relaxed that 15%. And we just continued we have continued
on that path. Thanks for that. Last one for me. What was the CO2 CapEx guidance
for the quarter? 91,000,000 dollars 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. So 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?
Yes, I mean, certainly some of the projects that we're doing on EP and G are those types of projects, very minor CapEx, just squeezing out additional capacity from our existing network. Intrastate, I think, are largely really sold out and that's a lot has a lot to do with why we're involved in GCX. So I would say those are really the 2 main areas. We've also found some opportunities off NGPL and some of that has been executed on and we are pursuing a bit more as well. So
I think all of those
are very low cost, high return opportunities and we're pursuing every bit of those that we can.
The other thing we've seen is and it's been in small chunks so far, but people looking for any outlet out of the Permian, including our Trans Colorado system, even Cheyenne Plains and Wick has seen some of the effects from the growth in the Permian Basin. So that's not expansion, that's existing capacity. So filling up kind of all the nooks and crannies coming out of the Permian to get to a different market.
Okay. And can you say any numbers at all, I guess, in terms of BPSI on how much more you can actually get out on El Paso and NGBL or too early to say?
Yes. That's hard to say. That's it's kind of a as you can tell from the map, it's kind of a network out there. And so 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. And then 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. And I think generally speaking in the Permian, there's not significant current crude by rail unit train capacity. So there's manifest capability, but a manifest cargo capability, but not unit train capability. Is that right? Okay.
Thank you. And then one last one. I think you touched on this when you discussed the hedges, but you've hedged your EOR production with WTI. But do you have crude transport out of the Permian or do you mostly receive a Midland price for
your barrels and are kind
of exposed to that spread?
We do have transport out of the Permian, including with our Wink Pipeline asset, which takes a significant amount of our production to Western Refining in El Paso. But we also, as part of our hedging program, we hedge quality and locational differentials. So we've hedged for 2018, we're at about 68%, I think, of Mid Cush hedged. 71%. 71% of Mid Cush hedged, and we're continuing to add to that position as we go through 2018.
Okay. That's very helpful. That's all great. Thank you.
The next question comes from Darren Horowitz with Raymond James. Your line is open.
Hey, Darren. How are 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 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. So one of the great things about the transition zone development is that we can it is sitting below the area that we are already developing with CO2. So that when we develop a project, we go hit the traditional CO2 flood zone and exploit that. But with a little bit of deepening and sometimes we can even use existing wellheads or wellbores for that deepening, we can access transition zone barrels. And so 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 found it. And so far we've found it in a number of places. And so I think roughly speaking, it's like 28%, 72%, 72% being seventy-thirty call it of traditional CO2 flood recovery with another 30 percent transition zone coming from that deepening. Is that about right, Jason? That's right.
So that makes it very capital efficient. That's the bottom line.
And how much of that, if any, is built into the $1,600,000,000 growth backlog forecast from 2018 out to 2022? Because I know that you guys have already experimented on what, 5 transition zone wells and the
budget this year is 2, is that correct?
That's correct. In terms of development.
Development dollars. Yes. There's very little of that is associated with the backlog. So this is very early, and we're still delineating the field. So there's it's very little of that 1,700,000,000.
And 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.
So Steve, as this evolves theoretically more focused
on the transition zone going
forward based on those rate of 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 1,600,000,000 dollars You're beyond any update that we've tried to do, Aaron. We're not there yet.
Okay. If I could, just one final question
for me on the Elba.
What's the expected timing of the liquefaction capacity between initial in service in the Q3 of this year and when you guys reach 10 liquefaction units by the middle of 2019? And also, how do we think about the timing of the remaining capital spend over those 4 quarters?
So, I mean, you have the time line correct. The first unit will be online in the Q3, and it's approximately 30 to 45 days sequentially from
that point.
So that gets us kind of into the late Q2, early Q3
of 2019. And as you probably recall, the return on the early economics on the liquefaction development are heavily weighted to Unit 1. And so Unit 1, we expect will be coming on and followed within roughly the sequence Tom laid out by Units 23 starting in the Q3. Unit 1 will not get in, in the 3rd quarter, but Unit 1 is expected to get in, in the 3rd 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 gross backlog.
The $900,000,000 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 Q4 update that we shared in January. Okay. So this is on top
of that. Could you just give color on maybe 1 or 2 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 Yes, I mean, our
G and P is about $500,000,000 and then the interstate projects across, I guess, really 3 different regions, another 300
Okay. That's the line share of it.
Again, of the 900, 820 is natural gas. So that's overwhelming majority of it is in the natural gas segment.
Got it. Okay. One just on Transfountain, 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 BC?
Yes. They're really 2 separate things. I mean,
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. And 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. And so we think of them as 2 separate 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. And my congrats to everyone there on the promotions. A couple from me, please.
Steve, I wonder if you 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. And 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 by 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. So the FERC has laid out a specific schedule in 3 or 4 tranches of filing of these 501 gs forms, right? And so that's pretty well defined, but that's just the beginning. There's a lot more and for reasons I said earlier, I mean 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.
So 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, the proposed rule. And 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. So the idea of 130 pipelines all getting done by the fall is not realistic. In terms of the 501 gs filings themselves, they have to be filed, is it I thought it was a 30 day process. Is that seems like you're indicating that there's some variance there? No, there's a phased in
and they've listed specific entities and what wave they're in. So there are specific dates for filing of 501 gs for each individual regulated system.
Okay. Okay.
4 separate waves.
Okay. Thanks for that. One quick question on the leverage number. You say, Kim, that it will be 5.1x or potentially below. And I just I want to just clarify that a little bit if I can in terms of that.
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 of weeks ago, there was some indication that it would be 2 times lower if that doesn't proceed.
Right. So 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 then the spending would ramp up. If Trans Mountain were terminated, then we think longer term, not this year, but longer term because you have incremental spending and would have incremental spending in future years, if you pursue 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. Got it, okay.
Okay. Thanks for that. And then 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 about a little bit about that with the wide diffs that surprised me a little bit.
It's rail service related. The service has been very visible in that area and Imperial has been negotiating directly with the CN and the CPE for improvements in that. And 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.
Right, right. That's why it surprised me. Any of that weather related or any particular reason, just
poor service?
It was all poor service related. Remember that facility is all 100% take or pay related. So it didn't have as big a financial impact, but 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, everyone. Hi. I just wanted to ask a couple of questions that came out. First of all, on Trans Mountain, I want to respect the fact that you're not negotiating publicly. But 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 or is this primarily a risk mitigation discussion similar to a surety bond where shareholder upside might remain intact?
Yes, Robert. Look, I appreciate
the interest and additional color. We're interested too. But there's really nothing more to add there. We have outlined 2 principles and I'm just going to restate them. There has to be a way to build through BC and there has to be a way to protect our shareholders.
And we are in discussions and those are the principles that we will be looking to preserve.
Okay. So you haven't taken anything off the table, I gather then? Any possibility?
We didn't say that. We just said some negotiations.
Okay. So Ben, you've answered most of my other operating questions. So 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.
But as far as I can tell, the press release is silent about David Michaels. So I'm wondering if he's going to continue his KML responsibilities as well?
Those right now the IR responsibilities for KML were under me. Now they'll be transition to Anthony Ashley who is our Treasurer currently and is today promoted from that Treasurer and Vice President of Investor Relations.
Okay. And then just finally, are these changes the timing, is it just coincidental with the news on Trans Mountain or is there any read through there?
No, no, there's no read through. No read through at all. And Robert, I want to confirm you're correct. Zacks will continue as Chief Financial Officer of KML.
Yes. Okay. Congratulations. Thanks, guys.
The next question comes from Robert Kwan with RBC Capital Markets. Your line is open. Good afternoon.
Robert, how are you doing?
Good. How are you doing? Good. Just wanted to ask on the Canadian M and A potential. And I'm wondering, first, do you need resolution on Trans Mountain before you really look in earnest on the M and A front?
And 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 the entire enterprise?
Yes. 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. Now we've defined that, 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. But there's no question it's uncertain and therefore makes it difficult for to evaluate M and A activity.
However, once we get to a point of clarity, the kinds of assets that we've always expressed interest in, in KML that is Western Canadian Midstream assets and still be what we would be looking at and looking for. It's not a large group of players there, but there are some very capable players with good midstream assets. And as you know, we have limited debt on this entity. And so it is something that we would want to look at. But I just think realistically,
when you started, when you start you were talking about players versus specific assets. And so I guess I'm also wondering, I can recall within the agreement between KMI and KML, KMI actually had the right to pursue corporate or publicly traded opportunities. So 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? 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. So we've been very broad about that. But the intent is and was that KML would be the vehicle to invest in those opportunities in Western Canada.
Got it. And if I can 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 withholding are you still holding the 2018 terminals guidance despite the shortfall in Q1? And how do you think you kind of pick up the rest then as you head through the rest of the year?
Yes. I think, specifically about terminals on KML.
And I
think our expectation is we'll come in, in line with Yes.
The big decrease was
at Van Moores, which was down $3,500,000 and it was broken down by sulfur which was one less vessel, we think that will catch up. At force majeure on copper, we think that will catch up. The only one that may not catch up is the agri volumes and that's going to depend on the railroads.
Okay. But does that catch up to run rate and exceed it to make up for Q1?
Is that
what you're saying?
To meet budget, yes.
Right. Okay. That's great. Thank you.
The next question comes from Brian Barron with Mizuho. Your line is open.
Good morning, Brian. Hey, Rich. I guess, circling back on your 2018 outlook to beat
to meet or
beat your guidance of $2.05 per share in DCF. Just to review your expectation as 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, then yes, those items would more than offset the interest expense.
Okay. And then 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. And then on interest expense, can you just remind us on floating rate exposure and updates on the impact of LIBOR being above your budget?
Right. So our the forecast that I just gave you, our guidance for the year to meet or beat our EBITDA and DCF, factors in the LIBOR curves as of the end of last week. So that is a 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 so it's about $100,000,000 of exposure for a full year impact of 100 basis points.
So you would have to have the 100 basis point increase starting January 1 and going throughout the full year to get to the 100,000,000
dollars And then just
shifting back to Trans Mountain, understanding that you're in negotiations on the expansion and the 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?
You're talking about the proposed Alberta legislation? Correct. Yes. 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.
I think there's going to be some back and forth here, and this is part of why we're seeking clarity, okay?
Appreciate that. And then my last question, just going back to FERC shifting to the liquids pipeline side, it's not for about 3 years from now. But looking at the new escalator taking effect in July of 2021, any initial thoughts on potential exposure to 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 or pipelines that are under index rates to that later date when they're going to be evaluating index overall. And that's really all we know at this point as well.
Thanks, Steve.
The next question comes from Ted Durbin with Goldman Sachs. Your line is open.
Good afternoon, Ted. Good morning.
Hey, how's it going? Just one question for me. If we sort of look at the FERC again and assume that the process that they've laid out sticks with this 501 gs form, I guess, can you help us out? I realize you're in the process of filing all your Form IIs and working through them, but if we could just take the headline number on maybe some of your larger pipelines where you don't have a more
a rate moratorium like Tennessee or EPNG. What sort of are we are you going to
be showing when you file your 2017
numbers?
Look, we do have more joy in Tennessee. The PNG 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. So it makes it hard to do quickly. I think that's the main point and there will 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 Form 2 filings and
we'll make them in a timely fashion.
The next question comes from Becca Followill with U. S. Capital Advisors.
Good afternoon, Becca.
Good afternoon. Back on 501Gs, 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?
I haven't seen we're still when 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. But the main thing that 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. And even then, I mean, it's hard to know how you can apply things like a one size fits all ROE on a 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.
So I think the 501Gs are going to create more fog than light.
We'd agree. And then second, you may have already commented that on Gulf Coast Express, any comments on potentially twinning that system? And 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 look for much synergy and construction there. Those are limited even when you set out to do it that way. It can be 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. Have a good evening.
This does conclude today's conference. Thank you for participating. You may disconnect at this time.