Williams Companies, Inc. (The)

Good day, everyone, and welcome to the Williams Company's first quarter 2019 earnings conference call. Today's conference is being recorded. At this time, for opening remarks and introductions, I would like to turn the call over to Mr. John Porter, Head of Investor Relations. Please go ahead.

Thanks, Devin. Good morning, and thank you for your interest in the Williams Company. Yesterday afternoon, we released our earnings press release and the presentation that our President and CEO, Alan Armstrong, will speak to momentarily. Joining us today is our Chief Operating Officer, Michael Dunn, our CFO, John Chandler, and our Senior Vice President of Corporate Strategic Development, Chad Cameron. I will also mention that we've refined our quarterly earnings materials and our format for this call. We've adopted a clear earnings press release format, and we've integrated the previous standalone analyst package into the earnings release document. So we now basically have one document there rather than two. In our presentation materials, you will find an important disclaimer related to forward-looking statements. This disclaimer is important and integral to all of our remarks, and you should review it. Also included in our presentation materials are non-GAAP measures that we've reconciled to generally accepted accounting principles. These reconciliation schedules appear at the back of today's presentation material. And so with that, I'll turn it over to Alan Archer.

Great. Well, thanks, John, and good morning, and thank you for joining us this morning as we discuss our first quarter financial performance in the key investor focus areas of the day. As John said, we took a fresh look at the format, and we're going to stay pretty brief and focused in our prepared remarks to allow time for Q&A. So let's move right into the presentation to take a look at our first quarter 2019 results. Here on slide two, we provided a clear view of our year-over-year financial performance, and the results you see reflect continued steady and predictable operational performance and strong project execution from our E&C team. And the results reflect very little direct commodity exposure. Our first quarter 2019 gross margin reflects 98% fee-based versus only 2% of direct commodity margin. And these contracted fee-based revenues are not dependent on basis differentials or commodity buy-sell transactions, allowing for continued predictability and durability in our cash flow streams. So taking from the top here, cash flow from operations increased 12%. demonstrating significant free cash flow in the quarter when compared with the 46% reduction in the capital expenditures you see at the bottom of the slide. I'll have much more to say about the adjusted EBITDA performance on the next couple of slides, but you can see here that it increased 7% year over year without adjusting for asset sales. And also, you see really nice improvement of 16% for our adjusted EPS, And on DCF, we were up about 8%, and we've also introduced DCF per share on this summary, which grew about 7% versus last year. And then lastly, our very strong 1.7 times dividend coverage also increased versus the prior year. So a really nice improvement in our various earnings and cash flow metrics despite the impact of some significant asset sales. And now let's turn to slide three and review where we finished the quarter on our leverage metrics. The leverage story at the quarter end requires some unpacking since we have significant asset sale proceeds coming in post the quarter's end. So starting on the left-hand side of the table, if you start with the debt to adjusted EBITDA directly from the March 31, 2019 financial statements, you get to a value of 4.92 times. However, that metric includes about $727 million in with a purchase of the remaining 38% interest in UEOM, which we funded partially with our revolver right at the end of Q1, but will be refunded with proceeds reserved at the closing of the UEOM OVM JV that we've done with CPPIB. A lot of letters there. If you adjust out that $727 million in cash we plan to receive at the closing of the JV, The leverage metric falls to 4.77. And then furthermore, if you account for the approximately 600 million additional proceeds we will receive from CPPIB at the closing of the JV, along with the 485 million we have now received from Crestwood for the Jackalope gas gathering transaction, the leverage metric falls to just over 4.5. So I'll discuss the strategic transactions and leverage goals in more detail later, but now let's move on to slide four to discuss the main business drivers for our year-over-year adjusted EBITDA growth. On a year-over-year basis, adjusted EBITDA increased just over 7% or 11% if you adjust for asset sales. And so on this slide, you can see a $37 million comparability adjustment driven by asset sales, including the adjusted EBITDA from the sell of Four Corners assets, the Gulf Coast Purity Pipeline, and the Brazos JV accounting changes. Now moving over to look at the financial performance of the continuing business, Atlantic Gulf led the increase with an over 20% increase in adjusted EBITDA, driven by top-line revenue growth from new expansion projects, including Atlantic Sunrise and Gulf Connector, Really very impressive growth from the Atlantic Gulf, driven primarily by continued projects that have been going into service on a regular basis on Transco. Next up, looking at the northeast GMP area, we also see just over a 20% increase in year-over-year adjusted EBITDA. This is driven by 15% higher gathering volumes and higher gathering fees associated with expansion projects. Volume increases were led by the Susquehanna supply hub area, which grew about 25%, but we also saw double-digit growth rates in the Marcellus South and Utica and high single-digit growth in the Bradford and OVM areas. So overall, very nice start to the year for the Northeast GMP. And finally, we have the West, which is showing about a 7% decrease in year-over-year growth adjusted EBITDA after adjusting for its share of the access sales described earlier. And that decline is primarily driven by lower NGL margins due to a temporary surge in natural gas prices at OPAL and the effect of severe winter weather affecting one of our key customers' production in the Wamsutter, Wyoming field. Importantly, our operations team in the area was able to keep our facilities ready and available, but upstream production freezing off was the culprit in the area. Next, let's look at the sequential adjusted EBITDA growth, where we saw about a 2% increase since last quarter. A modest increase in EBITDA for the first quarter of 2019 versus the fourth quarter of 2018, as you can see here on slide five. Of course, important to note that there were two fewer days in the quarter, which by itself is about 26 million, or 2% of an impact Atlantic Gulf was up about $30 million over fourth quarter, driven by lower O&M costs, and Transco revenues were higher related to Gulf Connector, but lower due to Gulf Star I volumes caused by well maintenance. Northeast GMP was pretty flat to fourth quarter, where increased revenue and lower O&M expenses were offset by lower wet Utica gathering, and J.B. Evadah from Oxable, for our interest in Oxable, and Blue Razor midstream. Recall that Oxable is a non-op interest in a processing complex in Illinois. And as we discussed in the past, the Northeast EBITDA growth in 19 is more weighted towards the second half of 19, and we'll be covering the outlook for the Northeast in more detail in a moment. Finally, the West was pretty stable compared to 4Q of 2018. Revenues in O&M were relatively flat sequentially, and per-unit NGL margins were quite a bit weaker. However, on a sequential basis, those lower per unit NGL margins were more than offset by the favorable change we had in our NGL line fill valuation margins. And as you may recall, our fourth quarter 18 marketing margins were unfavorable impacted by these same losses in marketing inventory. So as prices move up and down, the line fill valuation is something that swings up and down. Lastly, in the west, although we did see some nice sequential double-digit growth in the Hainesville, overall volumes were flat due to the severe weather in the first quarter of 2019, again from the warm-sutter volumes, which were down in one cube from weather as mentioned earlier. So generally Hainesville, we had some nice growth in the Hainesville, but it was pretty well offset by the warm-sutter volume declining from the freeze-offs there. In summary, 1Q adjusted EBITDA was within 1% of our business plan overall, and as we've said before, we see the overall 2019 growth to be weighted more towards the second half of the year due primarily to the shape of the Northeast EBITDA growth. So let's move to slide six, where we'll spend the remainder of the prepared remarks focused on our views around some of the topics we most frequently discuss with our investors. The first item we'll be discussing is our financial guidance update. A lot has changed since we originally issued our 2019 guidance about a year ago. From a macro perspective, we've seen our producer customers pressured to pull back on capital investment, and we've seen a significant downward shift in NGL margins. We've also had five important portfolio optimization transactions, including the Four Corners and DJ Basin transaction, the Brazos JV transaction, the sale of our Gulf Coast Purity business, our Northeast JV that we've mentioned, and most recently, the sale of our Niagara business. So lots of moving parts since we had laid out our guidance this time last year, but I'm pleased to confirm that despite these unforecasted changes, we are maintaining our guidance ranges for adjusted EBITDA, DCF, and dividend coverage ratio. We're actually raising our guidance for adjusted EPS to 95 cents at the midpoint due primarily to some lower depreciation expenses caused by last year's Barnett impairment and lower expected interest expense thanks to deleveraging efforts. If you look in the appendix at slide 13, you can also see that we've added a DCF per share metric and provided a bridge between DCF per share and EPS. We've had lots of discussions with investors about the very significant non-cast charges that impact our EPS, so we've given more visibility into those elements. On the growth capital expenditures front, we've seen quite a bit of changes since last year associated with the leveraging efforts and new projects like the Bluestem pipeline. And as we'll discuss further in a moment, we are targeting a lowering of our CapEx in the Northeast GMP business to respond to the producer activity in the region. So our teams are doing a really nice job of making sure that we bring that capital on just in time and don't get anything out in front of the drilling operation. So really nice work by our teams here that are constantly operating in a very agile mode up there. So when you net all of these changes, we're revising our consolidated growth capex guidance to a new midpoint of $2.4 billion, down from the $2.8 billion midpoint that was provided with our fourth quarter earnings relief. And when you factor in the new Northeast JV, our total contributions from JV partners this year take off another $120 million in addition to that $400 million reduction in the stated growth capital. And when you consider the proceeds we received from the Northeast JV and Niagara transactions, along with our excess cash after dividends, we expect to fund our 2019 capital expenditure needs with operating cash flows and proceeds from these transactions. The effects of our portfolio optimization transactions, along with our lower capital expenditure forecast, has had a favorable effect on our 2019 year-end book debt to adjusted EBITDA, which we now expect to be under 4.6 times. Looking beyond 2019, we are still expecting 5% to 7% annual adjusted EBITDA growth over the long term. So let's move on to the next topic, which is an update on the Northeast growth. As you'll probably recall, at our third quarter earnings call, we introduced forecasted 15% CAGR for the northeast area gathering volumes growth for 2018 through 2021. Since then, we've continued to work with our producer customers through two more forecasting cycles, and since last fall, delays and outages on Mariner East and delays on major gas takeaway pipelines like MVP, have dampened the realized price expectations for producers in the area on a forecasted basis. So despite this price decline, I am pleased to say that we are still expecting to see a 15% growth rate again this year on gathered volumes and a slightly higher EBITDA growth rate for the Northeast in 2019. Most of this is on the backs of great performers like Cabot and Southwestern, but increasingly we will see the impact of additional investments by Encino on their new Utica acreage. With the recent weakening of forecasted commodity prices, a few of our producer customers have focused on tuning their drilling capex directly to their free cash flows, and therefore producer forecasts at this point for 2020 and 2021 are very sensitive to forecasted pricing. And I think Very important to note there that a lot of the planning is done around forecasted pricing, and as prices change, we see producers shifting that, obviously. Right now, I would say with the depression we've seen in local NGL prices in the area, that has pulled some of the capital out of some of the wet Marcellus areas, and that is embedded in the forecast. We think it is wise and good for long-term sustainability for our producer customers to take this agile and measured approach, and we applaud the capital discipline. Over the long term, we believe that demand growth ultimately will drive producer volumes. Demand from converted power generation, LNG exports, and new industrial loads is continuing to grow after several years of heavy capital investment and construction, and now we are seeing a second wave as the Permian gas supplies further convince the world that the US has sustainable low gas supplies for decades to come. As a result, we don't believe that the current downturn in pricing is sustainable, giving the continuous growth in natural gas demand, coupled with the discipline we have seen from the producer community. And while Permian supplies are a needed resource to help fill the demand, we still have two-thirds of our gas supplies here in the US being generated by gas only directed drilling that will have to have a price signal and has become evident that we simply can't get the infrastructure built fast enough out of the Permian to keep up with the demand that continues to grow. While those fundamentals continue to support our steady and sustainable long-term growth, we do want to be transparent about the producers' forecasts as they relate to our near-term gathering volume and growth rates. Using the current detailed forecast from our producers, our gathering volume CAGR is expected to be a very impressive 10% to 15% growth through 2021, and while our EBITDA CAGR would still come out at or above 15% through the same period. Also on this front, I'm pleased to say that our capital programs are closely aligned with our producers, allowing us to reduce growth capex to more efficiently place capital against the same amount of producible reserves. So we're encouraged to see the level of EBITDA growth of our Northeast TMP business can continue to generate, even with reduced capital being applied. And this, combined with synergies from our new JV, will allow us to place capital more efficiently than ever in this important basin. Next up, let's get an update on our deleveraging efforts. We've had excellent execution this year on our portfolio optimization efforts. The Northeast JV transaction with CPPIB accomplished multiple benefits for the company. Consolidating the UEOM and the OVM systems while bringing up immediate cash for deleveraging and aligning us with long-term strategic partner who also owns and controls one of the most important customers in the area, Encino, Encino has attracted some very experienced and capable personnel, and we are excited to be forming another key mutually beneficial relationship in the region, much like we have with Cabot and Southwestern today. The Niagara transaction allowed us to accelerate deleveraging by exiting an area that wasn't strategically connected to the rest of our business network, and this transaction was priced at the same strong mid-teens multiples we realized in other portfolio optimization transactions. So no changes to our long-term leverage target of 4.2, which we target to hit by the end of 2021, while maintaining the 5% to 7% annual growth targets over this period. So let's move on to slide 7 and start with an update on the Transco rate case. As we previously discussed, we filed for an annual rate increase in our August 2018 filing, and those new higher rates went into effect on March 1st. So we're currently receiving the higher cash payments from our customers subject to refund, but you won't see that reflected in our results as we're reserving the increased pending ongoing settlement negotiations. On the settlement progress front, we've had two conferences recently, and we'll have another in May. The negotiations are confidential as long as we remain in the settlement process, so I can't share where we stand with the counterparties at this time. I can tell you that the settlement negotiations are likely to continue for many months and could extend into next year. We are hopeful that a settlement can ultimately be reached without the need for litigation and that the settlement would include the $1.2 billion emissions reduction investment opportunity. And we continue to present any upside from the rate case. Sorry, continue to not have any of that upside built from the rate case reflected in our financial guidance. And let's also touch on the status of Transco's major growth projects here. Lots of news out there these days and questions regarding the effect that the recent presidential executive order might have for our project. Obviously, William supports efforts to foster coordination, predictability, and transparency in the federal environmental reviews and the permitting process for energy infrastructure projects. Along those lines, we were actually very impressed with the level of detail that that appeared in the executive order on complex issues like the EPA's water quality certification requirements, and we are appreciative of the administration's efforts and in strong support of a sustainable approach to ensuring consistent application of EPA's regulations. However, we know that any major shifts in policies coming out of the executive order will likely be challenged by opponents of infrastructure and fossil fuels, no matter how clean. We deal with these permitting challenges on a daily basis, and our project development teams consistently do a great job of navigating those. And so beyond presidential orders, we continue to advance our key New York and New Jersey projects, like the Northeast Supply Enhancement Project, the Rivervale South Expansion, and our Gateway Expansion by demonstrating their critical importance to the markets they serve and the quality of our execution track record as was most recently demonstrated by our teams on Atlantic Sunrise. Transco's large-scale existing right-of-way and vast interconnection network are really the best way to bring clean, safe, affordable, and reliable natural gas to these northeast population centers that allow these regions to continue to lower the greenhouse gas emissions. And to that end, we continue to progress on the 20-plus Transco projects we currently have in development, including the most recently announced regional energy access project. The binding open season for regional energy access was extended from April 8th to May 8th to give shippers additional time to get the approvals they needed, not for just indications of interest, but for binding commitments. And we have been impressed with the interest the project has garnered. We are targeting a final investment decision in the third quarter of this year, with pre-filing to follow. And next up, I'll touch on our growth in the DJ Basin area. Since February, there have been ongoing developments in Colorado as the new executive and legislative leadership of the state took action to address oil and gas development laws. Ultimately, the new legislation seems to be a much more balanced approach than what we saw last fall with the failed Proposition 112. With the vast majority of oil and gas activity occurring in the industry-friendly Wells Counties, area, we welcome the shift in authority to local counties and municipalities, and we will continue to monitor as regulations are developed. In fact, our teams are working hard right now to keep up with the growth supported by a long backlog of currently permitted wells. Here in early April, we started up our new 200 million cubic feet a day Fort Lupton III cryo. The train is running very reliably and great job by the teams getting that started up safely. And construction is progressing very nicely on our Kingsburg number one cryo that should be online in the third quarter of this year. And in February, we signed up another new pack of gas along with NGL marketing rights right in that same area where we're continuing to develop infrastructure. So really very pleased right now with the strong demand for reliable and gathering processing services in the area. and we look forward to continued growth and support for our NGO marketing businesses, including the Bluestem Pipeline Project and associated upgrades at Conway. And next on to Deepwater. Last but not least, we have seen a steady increase in activity in the Deepwater Gulf of Mexico, where substantial new discoveries are being made in close proximity to our assets. This is an area where our existing assets and acreage dedications give us tremendous competitive advantages, and we are thrilled to see the dramatic rebound of activity that is focused on keeping costs and cycle times low by utilizing existing infrastructure like ours. This year, we'll see EBITDA contributions from our Norflip project, including those from the purchase of the Norflip pipeline and additions to our Mobile Bay processing complex that we did last year, and that is going to get paid for Actually, our Norfolk pipeline purchase gets paid for once first oil begins later this year, and we have line of sight to existing new potential business with likely FIDs in 2020 on several major projects that would lead to large incremental free cash flows on our existing asset base in 2022 and beyond. So as I promised on the introduction side, we tried to keep things brief today, but we're pleased to be able to update you on the solid first quarter performance. and great transactional progress that is accelerating our natural rate of deleveraging. With that, let's continue the discussion in our Q&A session.