金德摩根 (KMI) 2018 Q1 法說會逐字稿

Welcome to the quarterly earnings conference call. (Operator Instructions) 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 first quarter analyst call for both KMI and KML.

Before we begin, as usual, I'd like to remind you that today's earning 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, which 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 Michels 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 first quarter of '18, which Kim 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 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 continue to execute well on our growth projects. We placed $700 million worth of expansions into service during the quarter. And we continue 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 is on top of an 8% year-over-year increase that we had in the fourth quarter 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 Hiland 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 export's up 2%. And reminder, Kinder Morgan is about -- export's 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 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 line. These are short-haul moves, and the expansion capital is -- required is very modest. We're 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 Intrastate to serve our sales business in the State of Texas. That commitment is pending, and we would expect to conclude it soon. Attention, the basin is now turned underneath 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 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 to 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, 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 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 were on plan -- 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 Terminals 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 Base Line 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 1 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. 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 moratoria that we have in place and including 1 settlement we have pending before the commission right now, we do not expect to see an incremental negative impact in 2018 or '19 to our outlook. And 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 1/3 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 in several of our systems, which inhibit the reopening of existing rates.

Third, 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, prospective 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.

Fourth, an observation. We believe the 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 overearning, separate and apart from the impact of tax law changes. We believe this for a number of reasons. The 501-Gs ignore -- the instructions ignore important commission principles, including the NOPR's recognition of the status of negotiated arrangements. The form also used in 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 million a year, if fully implemented, which, again, we would expect would be delayed. It's incremental, meaning that's it on top of what we already assumed. We had already taken this into account on SFPP in our outlook and in our settle -- pending settlement on SNG, for example. This does not include other negative impacts from new rate proceedings, which we would -- 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 ratemaking, 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 bounces 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 the 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 are 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 Dang.

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 annualized 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, and then I'll move to Bcf, 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 change -- the new tax law. But 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 items 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 $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 Intrastate and SNG 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; and on FTC, 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.

Noncontrolling 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 '18 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 first quarter, 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 million, less the $26 million combined increase in sustaining CapEx and cash taxes and the $13 million increase in noncontrolling interest. That totals a $39 million increase in DCF versus a $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, so 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. And these 2 expenses were largely offset by 2 tax benefits items: first, the release of a tax reserve on the 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 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 1 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 noncontrolling 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 its 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 5.1x debt-to-EBITDA, flat to last quarter. In this calculation, we use 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 5.1x 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. Now that 600 and -- it'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've made share repurchases of $250 million. And then we have 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, 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 million, and that's because we make bonus payments in the first quarter and also there's significant property tax payments made in the first quarter. 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's at a decision point on the Trans Mountain expansion project. We announced the suspension of nonessential spending, and that, under current conditions, we would not put additional KML capital at risk. We also said there's 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 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. 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 at KML during the quarter.

Okay. Thanks, Steve. Let me process 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 third and fourth quarters of this year when we have comparable quarters all post-IPO.

Now moving to the result. Today, the KML board declared a dividend for the third quarter of $16.25 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, drive -- 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, and therefore, that gain does not recur in 2018.

Adjusted earnings, which include 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 the Q1 2017, with the Pipelines segment up $7.3 million and the Terminals segment down very slightly. The Pipelines 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 Wharves terminal, offset by the Base Line Terminal coming into service.

On the Baseline Terminal project, we placed 6 of the 12 tanks into service during the quarter. The first 4 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 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 31 was approximately $165 million.

For the quarter, net debt increased by approximately $129 million from December 31. And so let me reconcile that for you. DCF was $77 million. Expansion CapEx was $167 million. Gross 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 Base Line 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 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.

(Operator Instructions) Our first question comes from Jeremy Tonet with JP Morgan.

Just want to see, with regards to the FERC matters, if you had talked to the commissioners there. And do you have any sense if there could be any kind of reconsideration of what they've done here? It seems like some of the comments, maybe the employees 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 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.

Just a couple quick follow-ups and just want to see -- when you were talking about the moratorium, was that the FERC is prohibited from reopening where you have moratorium? Am I correct in understanding what you said there? And also just as far as how the suppliers of liquids pipeline, I was wondering if you might be able to expand a little bit there on the refined products side.

Yes. So the settlements really are applying to the gas pipeline side of the house, wherein ongoing rate case on SFPP has been going on for a very long time. And on the gas taking -- 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 to honor those.

Great. And then 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 can talk about the competitive dynamic as far as pursuing this project, if you look to bring that to the same market or 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 kind of widened out. So 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, 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. And 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 there's some and, with the right makeup of partners, there's 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 or crude out there. And 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, that 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 takeaway away from EPNG as these markets -- as these supplies are hunting markets.

The next question comes from Shneur Gershuni with UBS.

Congratulations to everyone on the promotion.

Thanks.

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 fourth quarter of '19 to the Gulf Coast is really the most realistic time line.

Okay, great. Just a couple of questions. First, 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, et cetera, 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 rollouts. 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 $5.8 billion of debt since late in 2015, and we've improved our multiple from 5.6x 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've 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 $555 million at the Analyst Day, in terms of its ability to continue buying back stock, and 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're 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, and so you could deduct that. And then as the capital moves around, the total expansion CapEx, which as Kim said, now rounds to $2.3 billion instead of $2.2 billion, you would also deduct that. Our projections which 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 Double H 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 Double H and therefore, there's no real need to really think about an NGL repurposing? Or is that 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 Double H. 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.

The next question comes from the Danilo Juvane with BMO Capital Markets.

Congrats to everyone who received a promotion 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?

I mean, 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. But depending on what happens with CapEx, there may be the opportunity to buy back more shares and/or pay down debt.

And 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?

Well, 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, 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. And 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 billion worth of debt. We are now -- as Kim says, we targeted 5.1x 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 weighing process between delevering and buying back shares.

Moving on to the backlog. I noticed in the release that you're now deploying organic growth ex Trans Mountain at 6x. I know that previously, we'd 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 the -- and so we will look at -- 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. We have -- I think the numbers you were talking about is more like 6.5x and 6.7x. 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 at 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 at 15% unlevered after-tax return, but we don't reject anything, we come in and discuss it, right. Some things that are better than the 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 derisks with long-term reservation-based contracts, we relax that 15% and we just continued -- we have continued on that path.

Last one for me. What was the CO2 CapEx spending for the quarter?

$91 million.

The next question comes from Jean Ann Salisbury with Bernstein.

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?

Tom?

Yes, I mean, certainly some of the projects that we're doing on EPNG are those types of projects, very minor CapEx, squeezing out additional capacity from our existing network. In cross states, I think we're largely, fairly filled 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 balanced 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 that we can.

And another thing we've seen is that 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 WIC, has seen some of the effects from the growth in the Permian Basin. So that's not expansions, 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 put any numbers at all, I guess, in terms of Bcf/d on how much more you can actually get out on El Paso and NGPLs? Or too early to say?

Yes, that's hard to say. That's -- it's kind of -- as you can tell from the map, it's kind of a network out there. And so it depends just on what installations you could put where, whether it's back pressure regulators, which are very cheap or compression, which is more expensive and other connections or things like that. It's a network.

Sure. 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.

And then one last one. I think you touched on this when you discussed the hedges. But you hedge 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 assets, 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 hedge?

71%.

71% of Mid-Cush hedge that we're continuing to add to that position as we go through 2018.

The next question comes from Darren Horowitz with Raymond James.

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 [a term] profile per barrel in order to monetize those incremental transition zone barrels versus some smaller fields? Because I know you had talked and you guys had 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 the -- one of the great things about the transition zone development is that we can -- it is sitting below the area that we're 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, Darren, 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. And so I think roughly speaking, it's like 28% and 72%; 72% -- 70-30, call it, of traditional CO2 flood recovery with another 30% transition zone coming from that deepening. Is that about right, Jesse?

Yes, that's right. I think you...

That makes it very capital-efficient, that's the bottom line.

And how much of that, if any, is built into the $1.6 billion growth backlog forecasts 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?

I think you're thinking 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 $1.7 billion.

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 $1.6 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? And also, how do we think about the timing of the remaining capital spend over those 4 quarters?

Tom, you want to speak?

So yes. I mean, you have the time line correct. But the first unit will be online in the third quarter and it's approximately 30 to 45 days sequentially from that point, so that gets us kind of into the late second quarter or late third quarter of 2019.

And as you probably recall, the return on that -- or the 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 2 and 3 starting in the third quarter. Units 2 and 3 will not get in, in the third quarter, but unit 1 is expected to get in, in the third quarter.

The next question comes from Keith Stanley with Wolfe Research.

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. That -- we put that in, in the fourth quarter update that we shared in January. But this is on top of that.

Can you just give color on maybe 1 or 2 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 -- or I can…

Yes. I mean, G&P is about $500 million, and then interstates projects across, I guess, really 3 different regions, that's another $300 million. That's the $900 million.

Again, of the $900 million, $820 million is natural gas. So 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 1 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 but related things.

The next question comes from Dennis Coleman with Bank of America.

My congrats to everyone there on the promotions. A couple for me, please. Steve, I wonder if the -- 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 2 views and maybe give some scale of how you think about the timing and 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-G 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 time frame. 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-G filings themselves, they have to be filed, is it -- I thought it was a 30-day process. Is that -- it 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 a 501-G for each individual regulated system by waves; 4 separate waves.

Okay. One quick question on the leverage number. You say, Kim, that you'll 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, it -- there was some indication that it would be 2x lower if that doesn't proceed?

Right. So what we've assumed in the 5.1x 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. Got it. Okay. 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 a little bit about that. With the wide dips that surprised me a little bit.

It's rail service related. The services bit -- vary a bit more in that area and the Imperial has been negotiating directly with the CN and the CP 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, that's weather-related or any particular reason or just poor service?

It was all poor service related. And 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 delivered.

The next question comes from Robert Catellier with CIBC Capital Markets.

I just wanted to ask a couple of questions on KML. First of all, on Trans Mountain. While I 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 that's similar to a surety bond where shareholder upside might remain intact?

Yes, Robert. Look, I appreciate the interest in 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 we're in negotiations.

Okay. So then 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 was silent about David Michaels. So I'm wondering if he's going to continue his KML responsibilities as well.

Those would -- 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 -- as 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. There's no read through at all. And Robert, you're -- I want to confirm you're correct, Dax will continue as Chief Financial Officer of KML.

The next question comes from Robert Kwan with RBC Capital Markets.

Just wanted to ask on the Canadian M&A potential, and I'm wondering, first, do you need resolution on Trans Mountain before you really look in earnest on the M&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 kind of the entire enterprise?

Yes. Well, 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, it makes it difficult for -- to evaluate M&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, would still be what we would be looking at and looking for. It's a -- 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 debts on this entity, and so it is something that we would want to look at. But 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 started -- or you started -- you were talking about players versus specific assets. And so 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. So can you talk about whether that was more theoretical and that the intention absolutely is for publicly traded entities and based on Western Canada to be within KML? Or how should we think about that side of things?

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 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, with holding -- 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 had to the rest of the year?

Yes, I think you're asking specifically about terminals on KML. And I think we're -- our expectation is we'll come in, in line with...

The big decrease was at Van Wharves, which was down $3.5 million, and it was broken down by sulfur, which was 1 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 but that's going to depend on the railroads.

Okay. But is that -- that's catch up to run rate and exceeded to make up for Q1? Is that what you said?

Simply to meet budget, yes.

Right.

The next question comes from Brian Zarahn with Mizuho.

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 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?

Yes. If we beat them, yes, those items would more than offset the interest expense.

Okay. And then 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, just remind us on floating rate exposure and updates on the impact with -- 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 million 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 million.

And then just shifting back to Trans Mountain, understanding that you're in negotiations on the expansion. In 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?

Are you 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 is 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 the fact of 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. And that's really all we know at this point as well.

The next question comes from Ted Durbin with Goldman Sachs.

Just one question for me. If we sort of look at the FERC again and assume that this process that they've laid out sticks with this 501-G form, I guess can you help us out? I realize you're in the process of filing all your Form 2s and working through them, but if we just take the headline number on some of your larger pipelines, where you don't have moratorium trail like Tennessee or EPNG, what sort of ROE are you going to be showing when you fire 2017 numbers?

Look, we do have moratorium in Tennessee. 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. So 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.

The next question comes from Becca Followill with U.S. Capital Advisers.

Back on 501-Gs. We've taken a look at them and agreed 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, what -- what's -- filing is due on the 25th?

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 501-Gs are going to create more fog than light.

We'd agree. And then second, you may already have commented, but on the -- 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 of the first phase?

I don't think you could look for much synergy in construction there. Those are limited even when you've set out to do it that way. It can be that 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.

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.