Kinder Morgan Inc - Class P (KMI) — Q3 2015 Earnings Call Transcript

Okay. Thank you. Before we begin, I’d like to remind you that as usual, today's earnings release and this call includes forward-looking statements within the meaning of the Securities and Exchange Act of 1934 as well as certain non-GAAP financial measures. We encourage you to read our full disclosure on forward-looking statements and use of non-GAAP financial measures set forth at the end of our earnings release as well as review our latest filings with the SEC for a list of risk factors that may cause actual results to differ materially from those in such forward-looking statements. With that out of the way, let me get to the meat of the matter. As usual, I’ll give an overview of the third quarter and, in addition, try to put some perspective on the happenings in our portion of the energy industry. Then I'll turn it over to Steve Kean our CEO and Kim Dang our CFO who will talk in more detail about 2015 and the outlook for 2016. And then as usual, we'll take any and all questions that you may have. Let me start by reviewing our 2015 performance. We raised the dividend for the third quarter to $0.51, and we expect to achieve our target of declaring $2 for full-year 2015. As you may recall, that’s an increase of 15% over 2014, and on top of that, we estimate we will have excess coverage for the year of about $300 million. Now, that's less coverage than our budget which assumes $70 WTI and $3.80 natural gas prices, and Kim will take you through the details of that variance. But still substantial in our view at the level of $300 million. To me, it demonstrates what we have been saying. That is that we are insulated from the direct and indirect impacts of a very low commodity environment, but we are not immune. Let me try to put things in perspective. If you take our $2 dividend and multiply it times 2.2 billion shares outstanding, that's $4.4 billion of cash distributions to shareholders that we will make for 2015. If you add to that $300 million in excess coverage, that means $4.7 billion of free cash flow after payment of all our operating expenses, our maintenance CapEx, and interest on our debt. Now we could have paid for all of our expansion CapEx for this year and had a lot of money left over. Our capital expenditure budget for this year is about $3.5 billion estimated for the full year. So with that in mind, I think that this idea that midstream energy companies like Kinder Morgan are not sustainable generators of cash flow just doesn't hold. Rather, we elected to distribute the bulk of our free cash flow to our shareholders and then pay for our expansion CapEx with a combination of equity and debt, and we intend to do this in the future. That said, we intend to continue covering all of our dividends with our generated free cash flow and remain investment-grade, watch our CapEx closely and continue, within those parameters, to grow our dividend. We're going to be judicious about using common equity, and as Steve will explain, we intend to use other means of raising equity so that we will not be required to issue common equity or access those markets through at least the middle of next year. Now let me also put in perspective our business and its prospects for the future. I talked about analogizing our business to a toll road, and I hope you’re not too tired of hearing it. I’m kind of sick of using it myself. And that phrase happens to be very true. But I want to give you some hard cold facts about the natural gas story which is our single most important business. As many of you know, our natural gas operations produce over half of our cash flow, and we move about a third of all the gas consumed in the United States. So, to put it very simply, as natural gas demand grows, so do we. Everybody talks about natural gas being the fossil fuel of the future because it's abundant, cheap, and clean, and that's all true. But I thought it would be interesting to give you some actual factual detail on what's really happening on both the demand and supply side of the natural gas story because it's so important to us and to other midstream companies. If you compare 2014 to 2015, McKenzie now estimates there will be an increase in demand year-to-year of 5%. It's projected to increase from today's level of 76 Bcf a day to about 110 Bcf a day by 2025, an increase of 40%. There are really four drivers of this growth. The first and probably the most interesting is electric generation. If you look at the 2015 mix of generating output, according to the EIA, 32% is gas and 33% coal. For those of you who have been in this industry a long time or followed it, you know that that represents a dramatic shift to the positive for natural gas. If you look ahead again to 2030, according to EIA numbers, their projection of the mix of generation is 39% gas and 18% coal. If you want to look at something closer to home, ERCOT in the state of Texas through July of 2015 had a mix of 49% natural gas versus 39% a year ago. Kinder Morgan specifically, our gas transportation volumes for electric generation are up 18% year-to-date 2015 versus the same period in 2014. Nationally, for the third quarter of this year, there was a 4.4 Bcf a day increase from the third quarter of 2014. These are real numbers, real occurrences that are happening in natural gas storage. Wood Mackenzie projects 8.6 Bcf a day growth in electric generation load from 15 Bcf to 25 Bcf. Renewables get a lot of attention, and they should, but let me put them into perspective. To be frank about it, they’re small and less reliable. Wind and solar combined generated less than 5% of total U.S. generating load in 2014. Capacity utilization for wind was 34% and solar 28%. That should not come as a surprise to anybody with any common sense because we should realize that the sun doesn't shine all the time and the wind doesn't blow all the time, but some people seem to have neglected that understanding. But what this means is that reliable flexible natural gas facilities are absolutely necessary to back up wind and solar. So to sum up, the idea that we could move directly from coal to renewables without increasing natural gas usage for electric generation is an unrealistic pipe dream. Added to the demand picture is the retirement of more coal plants due to environmental regulations and nuclear plant closures due to age and operational issues, and you put all that together, you have a very bullish growth outlook for natural gas and electric generation. There are other factors. The second demand driver is natural gas exports to Mexico. It’s real and it's growing. For 2015, natural gas exports to Mexico are expected to average 2.6 Bcf a day versus a 2014 average of 1.8 Bcf a day, an increase of 44%. This summer, we found that natural gas exports had at times exceeded 3 Bcf a day. Over the next four years, Mexico is expected to add 10.5 gigawatts of new natural gas capacity and it's expected that another 3.2 gigawatts of oil power capacity will switch to natural gas. Meanwhile, as most of us know, Mexico’s gas production continues to decline. Additionally, LNG imports to Mexico are on the decline and are expected to be completely phased out by 2023. All of these factors support projections that by 2025, natural gas exports to Mexico are expected to increase from the already elevated levels of 2015 by almost 3 Bcf a day. The third driver is the tremendous build-out of U.S. industrial and petrochemical facilities. The American Chemistry Council now counts 243 projects with a cumulative investment of $147 billion from 2010 to 2023. Texas alone accounts for 99 of those projects with a total value of over $48 billion, most of those in Southeast Texas, the heartland of our natural gas facilities including Houston, Corpus Christi, and Beaumont. Global chemical demand is expected to double from 2000 to 2040. Wood Mackenzie estimates that over 2.5 Bcf a day of additional natural gas will be required by 2018 from 2015 levels to meet industrial demand driven by these methanol, fertilizer, and petrochemical projects. Finally, let's talk about LNG exports. They are no longer years away. FERC approved LNG export projects have 10.6 Bcf a day of capacity. By the end of this year, Sabine Pass Train 1 will be in service with 650 million a day of capacity. By next year, with Sabine Pass Trains 1 through 3 online, LNG capacity will be 1.95 Bcf a day. By 2019, U.S. LNG export capacity will be 8.97 Bcf a day, counting only FERC approved projects which have achieved a final investment decision. These trends are driving U.S. demand towards the extraordinary growth I talked about to 110 Bcf estimated in 2025. Do we have the supply to meet that? The potential gas committee estimated that at the end of last year, we had nearly 2,900 Tcf of proven and potential reserves and that would be over 100 years of remaining resources relative to the current U.S. natural gas demand. Being affordable and abundant is important, so I want to stress again some facts about the environmental friendliness of natural gas. Natural gas emits about half the carbon dioxide of coal and over 30% less than fuel oil. In fact, natural gas is essential to national and regional efforts to reduce carbon emissions. The White House’s Council of Economic Advisers reported earlier this year, and I quote, 'natural gas is playing a central role in the transition to a clean energy future.' Since 2007, energy-related CO2 emissions in the U.S. have fallen by 10%, and significant factors contributing to this reduction were fuel switching from coal to natural gas for electric generation. In New England, the transition from coal and oil to natural gas from 2001 to 2013 resulted in a 23% fall in regional CO2 emissions, a 66% fall in NOx emissions, and a 91% fall in SOx emissions. What I’ve given you is a lot of facts, but they demonstrate that natural gas usage in this country is and will continue to be robust and growing for an extended period. For Kinder Morgan, which transports about a third of all the natural gas consumed, this paints a very positive business picture for years to come. And with that, I will turn it over to Steve.

Okay. From what Rich has just said, you can see why we are bullish about the fundamentals that drive our long-term value. I'm going to return to the shorter-term for a minute. I'm going to pick up on what Rich said about being judicious on the use of common equity. Because we are generating growing amounts of cash in our business, we have the flexibility to fund our investments in many ways, ranging from self-funding them with the cash that we generate all the way to distributing our cash to shareholders and accessing capital markets to fund our growth expenditures. We believe our investors value the latter, so we have been working within that framework. We believe we have found a way to break a cycle that we believe has negatively affected the value of our equity. Specifically, the challenging market for energy commodities this year has bled over to equity values for midstream energy companies. Because we have a significant backlog of growth projects, we have had to issue into this challenged equity market for the last two quarters, creating at least a perceived overhang in the market for our equity. We believe the market will value our common equity appropriately in the medium and long-term, especially our simplified large-cap C-Corp structure with a substantial and growing dividend. But until that happens, we sought alternative means to fund our growth capital needs without needing to issue shares in the common equity market for the rest of this year and into mid-2016. That means not having to use the ATM or underwritten offerings or bought deals or selling common equity at all for that period. Let me repeat that: we will not be selling common equity at all for that period. We've chosen the alternative we plan to use, which reflects our bullishness on the long-term value of our common equity. Our management team and board hold substantial common equity, so here's the bottom line for our equity investors. First, we're relieving whatever pressure that our common equity issuances had been having on the stock. Second, we're continuing to fund our growth projects, but at a lower long-term cost of equity capital than if we continued to issue common equity in today's market. Third, we're growing the dividend while maintaining coverage of that dividend. Finally, we are maintaining our investment-grade rating, which we believe positions us well for acquisitions and expansions in this environment. Before turning to the segments and the project backlog, there's an issue I'll address up front. When we did our consolidation transaction last year, we projected 15% dividend growth in 2015, with 10% annual growth from 2016 to 2020 and substantial excess coverage over that period. Here’s what we expect. We have not started our 2016 budget reviews with the business units yet, but we expect to be able to cover a dividend that is 6% to 10% higher than the 2015 dividend, which was 15% higher than last year. With what's happened in energy over the last 12 months, the coverage we projected last year in the consolidation transaction has taken a substantial hit. Nevertheless, while projections through 2020 are very assumption-driven, we believe we could still grow the dividend at the rate we projected last year; however, coverage would have been tight over the period and could have been negative part of the time. Other companies have elected to run at negative coverage, but we believe the prudent decision for KMI—and we believe the market is telling us this—is to continue to grow the dividend but preserve coverage over the period. Our underlying business is generating cash in increasing amounts, and for us it is not about finding a way to continue investing in attractive opportunities; it’s about finding the right combination of dividend growth and coverage and the appropriate alternative financing, and we think that in today's broader energy sector, that is an enviable position to be in. I'll turn to the backlog first. Since the July update, our product backlog decreased by about $700 million from $22 billion to $21.3 billion. We placed almost $400 million worth of projects in service during the quarter, the largest of which was the second splitter in the Houston Ship Channel which went into service early in the quarter. We added about $700 million for projects during the quarter, much of that coming from the terminals business unit. We also removed about $1 billion worth of projects from the backlog, the largest piece being further reductions in our expansion capital expenditures and our CO2 business as we moved some of our EOR and S&T investments outside of the timeframe of the backlog. In the third quarter, we produced $1.839 billion of segment earnings before DD&A, which was essentially flat to 2014, but this was largely due to decline in our CO2 segment year-over-year, not being fully offset by the year-over-year improvement in our Products and Terminals business segments. For gas, it was essentially flat year-on-year. We had commodity related volume impacts in our G&P sector and contract roll-offs on KinderHawk in May, partially offset by an additional volume commitment on the Eagle Ford from that shipper. We have the Kinder Morgan Louisiana contract buyout that took place last year affecting earnings before DD&A, as well as roll-offs on the Cheyenne Plains system. Now those last three items were all anticipated in our budgeting process and we're still on track in gas to slightly exceed the 2015 plan. We had higher transport volumes, up 5% across the segment, driven by a 50% demand increase for natural gas year-over-year and an 18% increase year-to-date, as Rich mentioned. We're seeing strong demand for long-term firm natural gas transportation capacity. We added 400 a day of firm long-term commitments during the quarter, bringing the total capacity signed up since December 2013 to 9.1 Bcf of new and pending long-term commitments. It's worth noting that of that, 1.6 Bcf comes from existing previously unsold capacity. So these signups are adding to our project opportunities and also making better use of the existing capacity that we have. We made great progress during the quarter signing up long-term commitments for capacity on the supply portion of Northeast Energy Direct, but we have not yet moved this product into the backlog depending on further progress on additional commitments. However, the prospects for adding this to the Northeast Direct Market Path product in our backlog materially improved during the quarter. We also had good progress on the Northeast Direct Market Path, going out with a customized offering for the electric load in New England, which is much-needed for gas demand. We had favorable rulings and recommendations in the state regulatory processes, improving our existing LDC contracts, and creating a good opportunity to secure the electric load that we need to make this project very attractive economically. We continue to see strong demand for existing and expansion capacity on our gas assets and believe we're well-positioned for the growth that Rich outlined that we see in the years ahead for those markets. However, we did have a setback on the Elba project as we received a scheduling order that has slowed the regulatory process by four to five months compared to our expectations. We may seek modifications to that order to try to improve on that schedule. Turning to CO2, earnings before DD&A were $282 million, down 22% year-over-year due to pricing reasons primarily and lower volumes as well. Our volumes are down year-over-year by 2% on a net basis, which can be explained by a timing issue on Yates. The net numbers you see in the release are based on sold volumes, but some of the production in Yates was produced in September but not transferred for sale until October, and that amount offsets the year-over-year downturn for the whole net production of the group. Second, production was down slightly for the quarter but up 6% year-to-date, on pace for a record year. Goldsmith and Katz were both up year-over-year, but continue to be below our plans. We have successfully implemented cost savings in this segment and continue to forecast reductions in our OpEx and maintenance CapEx of just under 25% for the year. We've also seen cost savings in our expansion projects, evidenced by the adjustments in the backlog; we're resizing that spending in this segment in light of the current commodity price environment. Turning to the Products group, segment earnings before DD&A were $287 million, up 29% year-over-year driven by the ramp-up of volumes on KMCC, our crude and condensate serving the Eagle Ford. The addition of Double H Pipeline from the Hiland acquisitions improved performance on SFPP, as well as better year-over-year results on Cochin. Early in the quarter, we placed the second of our two splitters in service in the Houston Ship Channel. Volumes are strong here with refined products up 2.5% year-over-year across our systems compared to a nationwide EIA growth rate of 1.5%, and year-to-date we’re running just over 3%. We continue to advance our Palmetto refined products pipeline project and our Utopia NGL pipeline project. Turning to Terminals, segment earnings before DD&A were $263 million, up 6% from last year. This segment is the tale of two cities. Our liquids business is performing very well in terms of ongoing business and growth opportunities, while our bulk business has been hit with a decline in coal and steel, compounded by the impact of the Alpha Natural Resources bankruptcy. Foreign exchange was also a negative factor for the Canadian portion of our terminals operations. On the liquids side, we're benefiting from higher renewal rates, particularly in Houston, and from expansions in Houston and Edmonton that we brought online, as well as additions to our Jones Act tanker fleet. We announced earlier in the quarter a joint venture with BP on approximately 9.5 million barrels of their refined product storage assets. This is exactly the type of deal we want to pursue with companies having midstream business assets embedded in a larger organization. We believe we can create a win-win with BP; they will contract for substantial capacity in support of their marketing activity, and we have the ability to operate and attract third-party business, operating these assets more efficiently. For Canada, the segment is down $8 million year-over-year, all of which can be explained by foreign exchange. The pipeline system itself continues to benefit from high utilization. The big news here is the Trans Mountain expansion project. We received our draft conditions in August, a bit later than we expected. We believe they will be manageable, though we did seek some changes for the time required to approve specific portions of the bill. One of our expert witnesses was appointed to the NEB, and out of caution, the NEB ordered us to file substitute testimony which we did in September. This resulted in delaying the date for their decision, their recommendation from the end of January 2016 to May 20, 2016. We're still working through the full effect of that, and the impact on our in-service date will depend on the final conditions we receive in May. However, we're going to do our best to give you an estimate of that impact, and we estimate an in-service date range between year-end 2018 and October 2019. There are lots of moving parts here, and we're working hard on our detailed project execution plan to optimize the outcomes, but that's the best guidance we can provide today. A reminder that this expansion is under long-term contracts approved by the NEB. We're excited about this project; it’s beneficial for our shareholders, and we're going to get it done, but we are indeed experiencing this delay. That is it for the segment and project updates, so I will turn it over to Kim.

Thanks, Steve. Looking at the GAAP income statement first before moving to DCF. On the face of the GAAP income statement, you will see that revenues are down significantly versus the corresponding period last year. You’ll also see that OpEx is significantly reduced. If you net out certain items impacting revenues and OpEx, the largest of which are the $198 million contract buyout on KMLA in the third quarter of 2014 and the CO2 mark-to-market. OpEx was down slightly more than revenue, both in the quarter and year-to-date. Changes in revenues are not necessarily a good predictor of our performance. We have some businesses where revenues and expenses fluctuate with commodity prices, but margin generally does not. We also do not think that EPS is a good performance indicator. But for those of you who need it, EPS without certain items is approximately $0.16 a share. We believe the better indicator of our performance is the cash we generate, which we express in DCF per share, as well as the dividend per share. So, with that, I'll go to our calculation of distributable cash flow. As Rich said, we're declaring a dividend today of $0.51, which is an increase of $0.16 over the third quarter of last year. Year-to-date, that results in dividends of $1.58, a 15% increase over the $1.48 declared for the nine months in 2014. We generated DCF for the quarter of $1.129 billion and $3.47 billion for the first nine months of the year, both significantly up over the prior year. The prior-year results are fused due to transaction closings, and a lot of the benefit in DCF is due to the fact that MLPs are no longer outstanding. You can see that benefit in the line entitled MLP declared distribution. Looking at DCF per share, it was $0.51 in Q3 versus $0.44 in Q3 last year, an increase of approximately 21%. Year-to-date, we generated $1.58 versus $1.29, a 22% increase. The $0.51 in DCF per share for the quarter results in coverage of about one times in the quarter, and year-to-date, we have coverage of well over $200 million. There are a couple of items of significance I should mention before I provide some details on our full-year outlook. We reported in the quarter a $387 million non-cash impairment on our Goldsmith deal, primarily driven by lower crude prices. The other certain items include fair value amortization and mark-to-market adjustments. We see those in most quarters with exceptions in the other category, including a $22 million write-off of receivables associated with the Alpha bankruptcy. That $22 million reflects revenues reported in periods before 2015. There's also a $50 million negative impact linked to 2015 revenues shown in the segment. This is consistent with our philosophy to strip out prior period one-offs and sporadic costs or benefits to show the ongoing cash-generating ability of our assets. Now for the full-year outlook. We expect to end the year with approximately $300 million in excess coverage, which is below our budget by about $350 million. However, that reduction is just 6% of our total BCF and about 5% of our EBITDA. If you utilize the metrics we provided in January, of the $10 million change in DCF for every dollar change incurred and a $3 million change in DCF for every $0.10 change in natural gas, the impacts on our results is about $235 million. That's approximately a $70 million deterioration from our expectations at the time of the second quarter call due to deteriorations in commodity prices. Our sensitivity assumed a constant NGL to crude ratio. That ratio has deteriorated from our budget, meaning that NGL prices have decreased more than crude prices. We estimate that impact to be less than $30 million. Direct commodity exposure accounts for a notable portion of our coverage variance. Lower CO2 volumes, lower midstream volumes, plus the decline in the Canadian exchange rate impact, when combined, represent about $100 million. Adding these items together gives a solid perspective on where we expect.</s> There are more moving pieces to consider. We see some benefits in interest expenses, along with CO2 and other cost savings. We've downsized in coal and steel in our Terminals business along with lower oil production volumes in our CO2 segment. We expect lower capitalized overhead as a result of reduced expansion CapEx. However, all of these net out to a small positive. Looking at the individual pieces for more granularity, we see natural gas ending the year slightly above budget, as Steve mentioned. We anticipate that the positive impact from the Hiland acquisition will be largely offset by lower commodity prices and decreased gathering and processing volumes in our midstream business. CO2 is expected to be approximately 15% below budget, a bit more than what our commodity price sensitivity would indicate. This is because of lower crude oil volumes, reduced CO2 volumes, and lower capitalized overhead, barely offset by about $43 million in cost savings. Terminals is expected to end the year about 6% below its budget, primarily due to lower coal and steel volumes. The largest portion is the $22 million effect of the Alpha bankruptcy and the FX impacts of a weaker Canadian dollar. Products will end the year slightly below budget, with the positive impact of Double Eagle pipeline acquisition being offset by about $20 million related to commodity prices affecting the segment, which is consistent with our sensitivity and lower volumes across several assets. KMCC is expected to finish the year below budget by about $20 million due to FX impacts. We expect to have positive variances versus our budget and on interest; however, we’re looking at a negative variance in G&A. These two items essentially offset each other. The variance in G&A is driven by the incremental G&A from the new Hiland employees and lower capitalized overhead as a result of lower expansion capital spending. About $3 billion was spent on expansion capital this year just under that. We plan to conclude ahead of budget. With that, I will turn it over to Rich.

Okay. And with that, Vance if you come back on, we'll take any questions you may have.

Hi, Shneur. How are you doing?

Good. How are you, Rich?

Good.

I guess if we can start off with your financing plans that you alluded to in the prepared remarks. You talked about widening of the dividend growth range which is probably prudent in this current market environment. But you also mentioned no need for equity into the second half of next year. I imagined excess dividend coverage is part of it but I was wondering if you can elaborate on how you're thinking about it, are you thinking about a convert? Is that something that the rated agency typically scores equity? Any incremental color would definitely be helpful to understand the financing plans for next year.

Well, unfortunately, SEC rules prohibit us from going into much more detail, but as Steve said, we have picked a vehicle and we intend to implement that.

Okay. Fair enough. I was wondering if we can talk about the backlog next. You've removed some projects from the CO2 bucket, but you also added $700 million worth of projects. I was wondering if you can talk about the sensitivity of commodity prices outside of CO2 concerning the balance of the backlog. Is there a price that you're considering now that serves as a benchmark for what gets into the backlog?

It’s really not commodity-price driven at all. What we are putting in the backlog outside of CO2, which is a little different, are projects that we have contracts on and we're waiting on permits. Some of the projects that are in the backlog are already under construction. We just don’t have revenue yet because they haven't gone into service. So these are high probability projects secured by contracts for which the customers are taking on what the volume is going to be and what the commodity price is going to be ultimately. With CO2, that’s a little different. It is driven more by a programmatic spend; we’re investing in development or expansion because we believe the pricing is there to support it. We try to be conservative in pricing and all of that. While in CO2 this year, with the results we have seen, we’ve scaled back investments. We had previously discussed the Lobos and Cortez pipelines, but we’re proceeding with that in part. We scaled back to deal with a current flattening demand in the CO2 environment. In summary, backlog additions are tied closely to project completion predictability and customer contracts.

Just one last question, you talked about the backlog being contracted and so forth. Could you remind us of your customer breakdown? If I remember correctly, you're not highly linked to the producers but more to utilities and industrial customers. Do you have that breakdown of customers as it relates to your backlog and legacy business?

Yes. There are a couple of ways to get at that. First, we have a very broad customer base. Very few customers account for even more than 1% of our revenues, covering utilities, producers like BP and Shell, refiners, and LNG producers. In terms of our growth, for the 9.1 Bcf of signed capacity, roughly one-third goes to LNG, another one-third to producers, and the remaining third goes to utilities and Mexico.

Great. Thank you very much.

Good afternoon.

Good afternoon, everyone. I guess, Steve, to get back to the financing question regarding alternative forms of capital, what do you need to change to be comfortable returning to the equity market? Is it just a yield problem, or is it a debt or liquidity issue for the common?

It's not a liquidity problem at all. We're a very liquid security, and the market has a significant appetite for our security. It’s primarily the cost of equity capital that's the issue right now, and what we believe we’re seeing is a temporary situation where the cost of our common equity is higher than it should be. We can access alternative forms of capital at a lower long-term cost of capital for this interim period. There isn't a magic number that we have in mind; it will be driven by the cost of our available sources of capital. We plan to demonstrate that we have flexibility in this regard. It’s important to note that we see ourselves having future capital access as we go forward.

Thank you. That’s actually very helpful. And then on the project side, Northeast Direct, is it fair to assume that demand tied to the power side of the project was dependent on the Massachusetts ruling? Is it necessary for other states to have similar rulings about gas supply into the generation rate base?

The PowerServe offering specific to power generators predates the Massachusetts ruling. However, the Massachusetts order was affirming, and we believe it recognizes the need for approving and recovering the costs associated with the needed upstream firm gas transportation capacity. Other states will have their own processes, but we remain optimistic about the developments. Additionally, just recently, another nuclear facility announced its closure, and the thought is there might be a second one. Removing several hundred megawatts from the grid without increasing the use of natural gas as a generation source is unrealistic. Natural gas has to play a significant role in meeting the electric generation needs, and it’s the underpinning of our Northeast Direct project.

Okay. Thank you very much, guys.

How are you doing?

Hey, fine. Thanks, Rich, hope you and everyone are doing well. Steve, just a quick question regarding your lower long-term cash to capital. Can you quantify the magnitude of cost to capital savings you have planned for reinvesting free cash flow versus the issuance of common equity burden by multiyear dividend growth ahead?

Unfortunately, Darren, I cannot get into those specifics. However, I can assure you that the savings are substantial enough to carry out our planned strategy.

Okay. If I could just shift gears back to your commentary regarding flexibility for third-party assets – how do you think the Northeast infrastructure supply/demand dynamic changes potentially impact both commercializing the supply portion of Northeast Direct and expanding logistics?

I think there are a lot of opportunities. The footprint and diverse assets we have provide a significant advantage in exploring those possibilities. Everyone is aware of the significant underutilization or underpricing of gas and liquids emanating from the fastest growing production region in America. Our first priority is to get that to New England, where the demand is highest. The ongoing reversing of the Tennessee system will facilitate our access, catering to both LNG and petrochemical loads disclosed earlier. New projects will in turn lead to even more opportunities, similar to how the Tennessee system has enabled us in recent years.

Thanks, Rich.

Hey, Mark, how are you doing?

Good. Just a quick question about the rating agencies; I think last call it was mentioned they were willing to tolerate elevated credit metrics until Elba and Trans Mountain contribute. I was wondering what your conversations have been with the rating agencies considering the delays?

This news on Trans Mountain and Elba is relatively new. If the projects are pushed, the spending is also deferred. What primarily drives the leverage to stay high is the fact that you're spending capital without cash flow coming in. However, we have active mechanisms to manage this.

And how do you link that to managing spending and retaining cash flow while dealing with a weaker fundamental environment?

I don't tie project delays to our coverage or dividend decision-making.

Just to clarify, as Steve and Kim have indicated, while we’re only starting our 2016 budget process, we’re providing a range. It will be lucrative. We’re maintaining the upper end of the range. It’s important to keep that in mind as we progress.

Thank you. That’s very helpful.

Hey guys, I appreciate it. Can you just help me clarify around the decision to lower the bottom end of the range to 6%? How did you settle on that number and what it implies for the longer-term range that people have been using, which is 17%, 18%, and 19%?

The 6% to 10% is just to reflect current uncertainties before we complete the budget process and ensures we can fulfill that while maintaining an appropriate amount of coverage. As for the longer term, you can't read too much into it; we need to evaluate the underlying assumptions along the way. If you look back to when we announced a consolidation transaction, we projected the need for rising capital spend. We've been physically on track regarding that capital, and while we've seen some adjustments due to project delays, there are still opportunities to invest.

I think historically you’ve been providing the budget update in December. Should I expect similar updates at that time?

Generally, we will update our guidance in January. However, it’s clear that the energy market changes have influenced our future dividend potential, which will influence coverage; we aim to balance that moving forward. We still expect strong underlying cash flow.

That's very insightful. Finally, could you touch upon your target leverage level for 2016 and 2017? What figure should I look at?

We expect to run at the higher end of the 5.6 range for several years until we get TransMountain and other projects in service, at which time we would anticipate a decline into the low-fives.

Thank you, guys. I appreciate your insights.

Ted, how are you?

Hello, Rich, doing all right. I suppose I hate to keep pressing coverage, but moving 8% to the midpoint for 2016, how do we gauge that on a multiyear basis? Historically you’ve maintained tighter coverage, are you suggesting that this lower for longer environment necessitates having a wider range?

Again, we believe the market is signaling to us that, given how things are being valued currently, the stability and coverage are priorities now. Thus, we want to balance a growing dividend while ensuring we have sufficient coverage, influenced by the longer-term cash flows generated by our business, which are still strong.

An important factor is that we continue to generate cash flow. If we want to grow at 10%, we can still do so. The challenge is balancing dividends under current market pressures.

Understood. Given your backlog and criteria, does the current evaluation change anything in your investment criteria regarding CapEx?

We still evaluate every project we pursue for the highest possible return. Our current backlog continues to be accretive and beneficial to investors, despite today's elevated yield and costs impacting capital. Careful scrutiny remains on project evaluations and returns.

I appreciate that insight. Lastly, I think you mentioned that you don’t expect to be cash taxpayers until 2020. I thought it was more likely 2017 or 2018; what changed?

We now anticipate not being significant cash taxpayers until 2020. The tax situation has improved in recent months, and we can extend the period during which we wouldn’t face significant cash tax burdens.

Great. I'll leave it at that. Thanks.

Good afternoon.

Good afternoon. I was curious about the alternative vehicle you mentioned. When would you be positioned to share more details? Is there any timeframe to when we may learn more?

There are no timelines at this point; I’m afraid it’s straightforward—you’ll know when we know, and you'll all learn simultaneously.

Got you. In terms of this vehicle, does it improve leverage or just keep you out of the equity markets? Any insights on that?

The key factors guiding our decision-making will focus on maintaining investment-grade ratings while maximizing shareholder value. We have to access capital markets at the right basis and keep a strong position for potential acquisitions.

Great. Thank you for the color. One last question regarding M&A. How do you currently view the market, and would this vehicle preclude any potential opportunities?

It does not preclude us from pursuing M&A opportunities. I'll let Dax Sanders, our VP of Corporate Development, provide insight on the current M&A market.

The M&A market can be categorized into three buckets based on value. For low to mid nine-figure asset deals, we’re starting to see opportunities, such as the recent BP deal. For asset deals in the higher range, we’re actively evaluating, but have yet to find appropriate valuation congruence. Lastly, with larger corporate deals, it’s more stressful and difficult to predict successful outcomes regarding timing. As we approach our next steps, we want to ensure that any M&A activity is rewarding for our shareholders. To summarize, our current focus is on acquiring opportunities that enhance our existing virtues and achieve appealing acquisitions significantly.

Nothing in our plan—while also maintaining our investment-grade rating—precludes us from exploring attractive M&A opportunities.

Any interest internationally, or is it primarily a North American focus?

We remain focused on North America for now. We’d need exceptionally high return projects to venture outside the region. We see plenty of opportunities domestically and maintain flexibility for the future.

Very helpful, thank you.

Hi Faisel. How are you doing?

Good. How are you doing, Rich? Thanks for your time. I'm curious about M&A with respect to your comments on cost and valuations. Would you agree there's a lot of negativity in the MLP and midstream space? What’s the current perspective on units being valued the same way?

Any transaction generally requires the convergence of three elements, practical assets, valuation, and conformity of stakeholder interests. Having all three come together is challenging and unpredictable.

Got it. What's your preferred mode of financing capital spending today?

To maintain investment-grade status, we ensure a mix of approximately 50% debt and 50% equity to achieve that goal.

Understood. Lastly, how do your debt issuance costs look today compared to six months ago?

While our spreads have widened a bit, treasury rates have declined recently, roughly making it more expensive than six months ago.

Thank you. On the backlog, does that incorporate the current steel costs compared to six to nine months ago? What’s the procurement plan?

We keep these factors up to date, with monthly reviews of costs per horsepower, ton of steel, and diameter of pipe. We're tracking these costs closely and actively evaluating contractor prices to ensure minimized expenditures. We're putting significant emphasis on protecting our costs, and we’re always looking for the best value providers to make the most of our capital investments.

To circle back to your earlier request regarding hedges on the CO2 side, we’re about 63% hedged at $72 a barrel for 2016. In 2017, we’re about 58% at $73. In 2018 it’s 45% at $75, and 2019 is 24% at $66.

That’s very useful context, thank you.

Thank you, everyone, for bearing with us for an hour and a half of informative questions. Have a good evening.