Oneok Inc (OKE) — Q4 2019 Earnings Call Transcript

Thank you and good morning, and welcome to ONEOK's Fourth Quarter and Year-End Earnings Call. This call is being webcast live, and a replay will be made available. After our prepared remarks, we'll be available to take your questions. A reminder that statements made during this call that might include ONEOK's expectations or predictions should be considered forward-looking statements and are covered by the safe harbor provision of the Securities Acts of 1933 and '34. Actual results could differ materially from those projected in forward-looking statements. For a discussion of factors that could cause actual results to differ, please refer to our SEC filings. Our first speaker this morning is Terry Spencer, President and Chief Executive Officer. Terry?

Thanks, Andrew. Good morning, and thank you all for joining us today. As always, we appreciate your continued trust and investment in ONEOK. Joining me on today's call is Walt Hulse, Chief Financial Officer and Executive Vice President, Strategic Planning and Corporate Affairs; and Kevin Burdick, Executive Vice President and Chief Operating Officer. Also available to answer your questions are Sheridan Swords, Senior Vice President, Natural Gas liquids; and Chuck Kelley, Senior Vice President, Natural Gas. 2019 was an outstanding year, a year of project execution and record-setting safety performance for ONEOK, positioning ourselves for exceptional growth in 2020 and 2021. Yesterday, we announced fourth quarter and full year 2019 results, announced our 2020 guidance and provided a 2021 outlook. We also announced three expansion projects that will further strengthen ONEOK's position in the Williston and Permian Basins, and increase the needed natural gas processing and NGL transportation capacity for our customers. It is important to point out that these high-return projects build off of our existing assets. These projects include the Demicks Lake III plant in the Williston Basin, the full expansion of the Elk Creek pipeline to 400,000 barrels per day and the fourth expansion of the West Texas LPG pipeline since October 2017. Our growth program is providing critical natural gas and NGL infrastructure to our customers, including assets to help significantly reduce natural gas flaring in the Williston Basin and provide increased connectivity all the way to the Texas Gulf Coast. Upon completion, our announced projects will expand the backbone of our NGL business and will add processing capacity to further strengthen our position as a leading midstream service provider. As for project updates, we announced that Elk Creek was completed in mid-December, Demicks Lake I and II were completed in October 2019 and January 2020, respectively, and the first phase of the MB-4 fractionator was completed in late December. Kevin will provide more color on the projects that are slated for completion here in the first quarter. Our last earnings call in late October, I made a comment that 2021 is setting up to be another year of double-digit growth. With many of our projects being completed this year and into next year, we are confident in our 2020 earnings outlook of adjusted EBITDA increasing approximately 20% compared to our 2020 guidance midpoint. With that, I will turn the call over to Walt.

Thank you, Terry. ONEOK's 2019 net income totaled $1.28 billion or $3.07 per share, an 11% increase compared with 2018. In 2019, adjusted EBITDA totaled $2.58 billion, a 5% increase year-over-year. Natural gas liquids and natural gas volume growth, higher average fee rates and increased transportation capacity contracted, all contributed to a strong 2019 performance. The natural gas gathering and processing and natural gas pipeline segments ended the year with adjusted EBITDA increases of 11% and 12%, respectively, compared with 2018, exceeding the high end of the 2019 guidance range in both segments. The natural gas liquids segment adjusted EBITDA increased 2% compared with 2018, about 4% below the low end of the 2019 guidance range, due primarily to narrower-than-expected NGL price differentials. Distributable cash flow for 2019 was $2.02 billion, up 11% compared to 2018, with a healthy full year dividend coverage of 1.38 times. We also generated nearly $560 million of distributable cash flow in excess of dividends paid in 2019. Our annual dividends paid during 2019 were $3.53 per share, a 9% increase compared with 2018, in line with our previously stated guidance. And in January, the Board of Directors declared a dividend of $0.935 or $3.74 per share on an annualized basis, also an increase of 9% compared with the first quarter of 2018. Our December 31 net debt-to-EBITDA on an annualized run rate basis was 4.8 times. We continue to expect to be at 4 times debt-to-EBITDA run rate in late 2020 or early 2021 with deleveraging continuing thereafter as volumes ramp and additional projects come online. We ended the year having no borrowings outstanding on our $2.5 billion credit facility and $220 million of commercial paper outstanding. As Terry mentioned, with yesterday's earnings announcement, we provided detailed 2020 financial and volume guidance and a 2021 outlook. Our 2020 guidance includes increases in our earnings per share and adjusted EBITDA midpoints of 16% and 25%, respectively, compared with 2019. We expect double-digit year-over-year earnings growth in our natural gas liquids and our natural gas gathering and processing segments of 15% and 11%, respectively. Our natural gas pipeline segment had a strong 2019, and we expect another solid year of performance for the segment in 2020. Key drivers to achieving our 2020 financial guidance expectations include volume growth expected from the Elk Creek pipeline and the Demicks Lake processing plants, and contributions from the Arbuckle II pipeline, the MB-4 fractionator and the second West Texas LPG expansion, all projects that we expect to be completed here in the first quarter. Our 2020 growth capital guidance range of $2.25 billion to $2.73 billion is a significant decrease compared with our peak capital expenditure spend in 2019 and incorporates the projects we announced yesterday. As a reminder, what we call routine growth capital such as well connections and plant connections is included in this number. Our 2021 outlook of an approximate 20% increase in adjusted EBITDA compared with the 2020 guidance midpoint is driven by continued volume growth on Elk Creek resulting from the increased volumes from plants connected in 2020, the Bakken NGL pipeline extension and the Bear Creek expansion. Volume growth in the Permian Basin and the Gulf Coast from the completion of the MB-5 fractionator and the third and fourth expansions of West Texas LPG pipeline will also contribute to the 2021 increase. With these project completions this year and early next year, total capital expenditures are expected to decrease significantly in 2021 relative to 2020.

Thank you, Walt. 2019 was an impressive year with strong producer activity across our operations, driving NGL raw feed throughput and natural gas processed volume increases of 7% compared with 2018. We expect volumes to continue to increase in 2020 and our earnings to remain more than 90% fee-based. As Terry said, we completed our Demicks Lake II plant in the Williston Basin in January and expect to complete three additional NGL projects by the end of the first quarter. Overall, our projects are on time and on budget, positioning us well for continued growth as volumes on these projects ramp up. Let's start with our Rocky Mountain region, which includes the Williston and Powder River Basins. Producer activity remains strong in both the Williston and Powder River basins. North Dakota continues to see natural gas production of more than 3 billion cubic feet per day, and the basin-wide rig count remains in the 50 to 55 range with approximately 25 rigs on our dedicated acreage. Rig counts have remained consistent in this $50 to $55 WTI crude oil price environment, which we expect to continue. Natural gas volumes processed in the Rocky Mountain region increased 11% in both the fourth quarter and full year 2019 compared with the same periods in 2018. Processed volumes averaged 1.05 billion cubic feet per day for 2019, above the midpoint of our volume guidance range. We expect processed volumes from this region to increase more than 25% compared with 2019 due to the completion of the Demicks Lake plants as we significantly reduce gas currently being flared. We connected 526 wells in the Rocky Mountain region in 2019. Better-than-expected well performance and higher gas to oil ratios contributed to volume growth even with producers temporarily delaying well completions until our Demicks Lake plants came online. We expect to connect between 575 and 625 wells in 2020. Our 200 million cubic feet per day Demicks Lake I natural gas processing plant that was placed in service in the fourth quarter is expected to be full by the end of the first quarter. We expect our Demicks Lake II plant to ramp to full capacity over the next 12 to 18 months. With the latest reported natural gas flaring data of approximately 500 million cubic feet per day in the basin and approximately 300 million of that on ONEOK's dedicated acreage, we now have the capacity available to capture a significant portion of this flared gas. Our Bear Creek plant remains on schedule to be completed early in the first quarter of 2021, which will provide much-needed processing capacity to the highly productive geographically isolated Dunn County area, where we have substantial acreage dedications. The Demicks Lake expansion will provide an additional 200 million cubic feet per day of processing capacity when it is completed in the third quarter of 2021. With the completion of these two facilities, ONEOK will have approximately 1.9 billion cubic feet per day of processing capacity in the Williston Basin. NGL raw feed throughput volumes in the Rocky Mountain region, which consists of Elk Creek and the Bakken NGL pipeline, increased 9% compared with the third quarter 2019 and 23% compared with the full year 2018. We expect our Rocky Mountain NGL volumes to continue to increase as approximately 850 million cubic feet per day of processing capacity from ONEOK and third-party plants has come online since the third quarter 2019. We recently reached more than 230,000 barrels per day of raw feed throughput on Elk Creek and the Bakken NGL pipeline combined and continue to expect to exit the first quarter of 2020 with more than 240,000 barrels per day. Yesterday, we announced an expansion of the Elk Creek pipeline to its full capacity of 400,000 barrels per day. The expansion is supported by well over 240,000 barrels per day of long-term dedicated production from ONEOK and third-party plants, excluding any incremental ethane. Of the 160,000-barrel per day expansion, approximately 60,000 barrels per day of the capacity is expected to be available in early 2021 and the remaining 100,000 barrels per day by the third quarter of 2021. We also continue to see growth in the Powder River Basin as production results remain strong, benefiting both our natural gas gathering and processing and natural gas liquids segments. Moving on to the Mid-Continent. Natural gas volumes processed increased 3% year-over-year, above the midpoint of our guidance range, connecting 117 wells to our gathering and processing system. Based on recent discussions with our customers, we expect our natural gas volumes processed in the Mid-Continent region to decrease approximately 10% this year compared with 2019 and expect to connect 40 to 60 wells. Total NGL raw feed throughput in the Mid-Continent region for the fourth quarter decreased slightly compared with the third quarter, due primarily to spot volumes in the third quarter that did not carry over to the fourth quarter. Outside of ethane rejection, we expect relatively flat Mid-Continent volumes on our system in 2020 compared with the fourth quarter 2019. During 2019, we connected 5 new third-party processing plants to our natural gas liquids system in the region, and 2 previously connected third-party plants on our system were expanded. Our Arbuckle II pipeline remains on schedule for completion by the end of the first quarter of 2020. Arbuckle II will play an important role in transporting incremental supply from the Williston and Powder River Basins, the Mid-Continent and the Permian Basin to the Gulf Coast. Arbuckle II is the lower end of the NGL backbone and will be our fifth pipeline that can funnel supply from across our entire system to the Gulf Coast markets. Finishing with the Permian Basin and Gulf Coast. NGL raw feed throughput volumes in this region increased 22% year-over-year, and the average fee rate increased compared with the third quarter 2019. We expect average rates to continue to increase as we bring on new volumes with bundled rates from our completed expansion projects. We announced our fourth expansion of the West Texas LPG system, a 100,000 barrel per day fully contracted expansion with long-term dedicated production from third-party processing plants in the region. We now have announced approximately 260,000 barrels per day of expansions on West Texas LPG to support volume growth in the region. Our system-wide NGL fractionation capacity remains highly utilized. Phase 1 of our MB-4 fractionator, which was completed in December, has increased our capacity by 75,000 barrels per day. Phase 2 of the project, which will add the remaining 50,000 barrels per day of capacity, remains on schedule for completion by the end of the first quarter of 2020. And our MB-5 fractionator remains on track for completion in the first quarter 2021. Our overall NGL segment raw feed throughput volume guidance is expected to increase 15% in 2020, driven by a full year of operations of Elk Creek and the completions of the Arbuckle II pipeline, the MB-4 fractionator and the 80,000 barrel per day West Texas LPG pipeline expansion, all expected in the first quarter of 2020. Continued growth from plant connections and expansions completed in 2019 will also contribute to higher volumes in 2020. We expect 6 to 9 new third-party plant connections or expansions, including the connection already completed with Demicks Lake II. Terry, that concludes my remarks.

Thank you, Kevin. 2019 was another successful year for ONEOK, and I'm proud of our employees who continue to focus on safety, reliability and the execution of our growth projects. Operating our integrated network of assets in the manner for which ONEOK has a strong reputation remains our focus and is the foundation for all our successes we've discussed today, and will continue to be as we move forward as we transition from this build cycle to a period of significant cash flow generation. Thank you to all our dedicated employees for your hard work and contributions in helping us achieve another year of company-wide growth in 2019. And 2020 is off to a great start as we are in the middle of many project completions and new asset operations that will position us well in the coming years. With that, operator, we're now ready for questions.

I appreciate all the insights on the expansions. Could you provide a brief overview of the differences in capital expenditures between Demicks III and the previous two, as well as the Bear Creek expansion? It seems you have achieved significant efficiencies. Should we view the cost differences as an opportunity for an improved return profile for Demicks III compared to the others?

Yes, Tristan, this is Kevin. That's how we view it. The reduction in capital is primarily due to expansions we've undertaken with Demicks I and II, including aspects like power, inlet handling for the plant, and some pipeline infrastructure. We're focusing on expanding existing compressor stations instead of constructing new ones. All these factors are contributing to the lower capital costs compared to our previous projects.

Helpful. Regarding the Elk Creek expansion, should we consider the volumes primarily to support Demicks III and Bear Creek, or are there other third-party plants involved in this latest expansion?

Yes. I mean, that's the way to think about it. As we continue to ramp volumes with more than 240,000 barrels a day now of contracted on the pipe, we needed to expand it. We also wanted to make sure we had the ability to handle any ethane that needs to come out incrementally. But again, the economics are really based more on just the traditional, the classic C3 plus volume growth that we see. We still have a lot of opportunities, and we're in late-stage negotiations with several customers north of the river as we build that lateral that's going to connect over to the Hess plant. So there's still opportunities out there in front of us.

I would like to discuss the 2021 plus 20% EBITDA guidance in more detail. I'm trying to understand the assumptions behind it, particularly regarding the ramp-up of Elk Creek and the expected ethane recovery from the Bakken. Are you anticipating full ethane recovery? Additionally, could you explain the margin uplift and describe the differences between your assumptions for 2020 and 2021?

Sure, Shneur, this is Kevin. It’s clearly focused on the Bakken area. You can start looking at the list of projects that are set to launch either late this year or early next year. The Bear Creek II expansion is one, which will have some flared gas available once operational. We have four large, well-capitalized producers eager to drill there, but currently lack capacity. There's potential for growth. We also have the north lateral from our NGL segment that will connect to the Hess Plant, expected to be completed in the fourth quarter of this year, which will give us a full year of volumes from it. Our existing facilities, like the Demicks Lake plants, are continuing to grow, and we might see some opportunities with Demicks III later this year. Additionally, we have a modest amount of ethane; based on our production growth and capturing flared gas, we anticipate needing to extract some ethane. We expect to extract about 25,000 to 40,000 barrels per day of ethane in 2021 due to the BTU heat content issue on Northern border. In the Permian and Gulf Coast, three expansions are set to be operational between now and the middle of 2021, which will contribute to further volume growth. We will also benefit from a full year of the MB-5 fractionator in 2021. Overall, we expect continued volume growth in both our NGL and G&P segments, projected to be well into double digits.

That was very helpful, and I really appreciate it. As a follow-up question, I have a two-part inquiry, if that's alright. Regarding your capital expenditure activity, even with the announcement of new projects, it seems to be lower than in the past, and there appears to be a slowdown in producer activity. I'm curious about the opportunities for ONEOK to pivot and optimize costs. Are there expenses that can be eliminated now that you have better visibility into your business operations? Additionally, is there a possibility for you to pursue an asset-light strategy? Considering your Elk Creek expansion and the West Texas LPG project, which will significantly increase volumes on the NGL side, it seems like you would require a fractionator. However, given the excess capacity of fractionators in the market, are there ways for you to sublease from others and leverage that in an asset-light strategy? I'm interested in hearing about any other approaches you might have for optimizing earnings growth beyond 2021.

Yes, Kevin again. I think we have already been pursuing that in many ways. The previous question about Demicks Lake is a prime example of a brownfield expansion where we implemented it. Additionally, we were able to significantly lower the capital required for that capacity. In terms of fracs, we have made similar advancements. We have a clear view of MB-4 reaching full capacity with substantial volumes, if not MB-5 as well. It's worth noting that we have announced an expansion of approximately 65,000 barrels a day at our existing facilities, which our team was able to achieve for much less capital than constructing a new greenfield frac. This has postponed any discussion regarding an MB-6 since our team has effectively identified opportunities for debottlenecking and expansion. I want to commend our team for their efforts. This approach is ingrained in our operations as we strive to provide capacity for our customers. Regarding your initial comment, I would like to express my perspective; we have not observed a slowdown in producer activity on our acreage, particularly in the Bakken and Permian regions. While the Mid-Continent has seen a decline, we have not noticed any decrease in activity in the Bakken or Permian at all.

No. Fair enough. I appreciate the information. I have one final question. When do you expect your next projection for ONEOK to indicate that it will be a cash taxpayer?

Shneur, as we've mentioned previously, when we acquired the partnership in 2017, we indicated that we would not be a taxpayer until 2021. We have built assets valued between $6 billion and $7 billion with bonus depreciation that we have been leveraging. This gives us a substantial runway before we begin paying taxes. Eventually, there will be limitations on the use of the net operating losses established under the last tax legislation. However, looking ahead, we anticipate having a marginal tax rate of around 4% to 5%. Therefore, we do not expect to fully enter a tax-paying status for quite some time.

If I could start with a follow-up regarding the ethane extraction in the Bakken. Should we view the ethane extraction you'll potentially undertake next year as a temporary measure until another pipeline is operational and more Canadian gas can blend with the Bakken gas? Or do you believe it will be more of a permanent arrangement?

Christine, this is Kevin. I think we believe it's going to be a long-term thing. Because if you think about new capacity, any new capacity that's going to come online in the Bakken, it is highly likely it's going to have a BTU spec on it also because it's not going to have other gas to blend down with like currently is going on Northern border. So at least the various projects that we've looked at and been involved with, all of those contemplate a BTU spec.

Okay. That's what I thought. Just wanted to confirm. And then could you give us a breakdown of where the 6 to 9 third-party plant connections are regionally?

Christine, this is Sheridan. The connections will primarily be in the Bakken and Permian regions, with approximately equal distribution between the two. Growth will come from some plants expected to begin operations at the end of 2020, which may either start in 2020 or continue into 2021.

Okay. And is the growth primarily Bakken? Or that's also split between Permian and...

It's split.

Okay. And then can you give us an idea of the cadence and the magnitude of the third-party frac costs and rail cost roll off in 2020?

Yes. Christine, we won't see any third-party rail costs in 2020 or we haven't predicted any since Elk Creek coming online, that has been reduced to 0. But the third-party frac will be about the same level it was in 2019 as in 2020 as we get ready for MB-5 coming online.

Just wanted to follow-up, I guess, with your conversations with producers in this environment and given how the commodity price has declined a bit here. Just wondering if you could relate with us, I guess, expectations for drilling activity. Has that been moderating? Or it seems like it'd all be firmly baked into your guidance at this point, but anything that you can share with us, I guess, on this topic?

This is Kevin. We are examining the commodity environment in a way that's quite similar to our producers. Our primary focus is on crude oil. We have significantly reduced our direct commodity exposure, so fluctuations in NGL prices or natural gas prices are not very impactful for us. Most of our producer customers are planning for a $50 crude oil environment, which leads us to assume similar activity levels in regions like the Bakken and the Permian. This outlook extends over the next couple of years and aligns with our customers' perspectives.

That's helpful. And just a couple of cleanup questions, I guess, with the NGL logistics side. How do you guys sit on the storage side at this point? Do you think that there's more expansions that are needed there to kind of do what you want to do in Belvieu? And then in the 2021 guide, I guess, the Conway-Belvieu spread, any thoughts you could share with us on how that lands at that point?

We are currently in the process of building two new storage wells, each with a capacity of 1.5 million barrels, and we are also developing a 3.5 million barrel brine pond. We recognize the need to expand our storage facilities, and we are taking action to do so, with one of the wells expected to be operational this year and the other next year. This expansion will position us well to accommodate our growth. Additionally, regarding the Conway to Belvieu spread, we anticipate that the spreads will be very narrow with the Arbuckle II pipeline coming online. In our guidance for 2020 and 2021, we are expecting to see a historically low or very narrow spread between Conway and Belvieu.

Got you. Great. And just to confirm, I think you had said $50 to $55 is kind of the price deck that you guys are employing when you think about this guidance going forward?

Yes. From a crude activity perspective, that's the level we're thinking about it.

A couple of questions. First of all, when thinking about flaring and flaring limits, just curious do you think there's potential for North Dakota to tighten the flaring limits further? And if so, what would have to happen for that? And second, do you have any read-through or read into the recent report put out by the Railroad Commission in Texas regarding flaring there?

Michael, it's Kevin. I'll begin and then let Chuck join in. The flaring and gas capture targets in North Dakota will change at the end of this year, increasing from an 88% capture rate to 91%. This clearly indicates a step up in discussions we are having with the state and our producers. Our goal is to reduce that number even further. Looking back at 2015 and 2016, when the midstream sector was strained, we were able to achieve lower flaring levels. That's what we aim for. Regarding Texas, we noted the recent report. From a regulatory standpoint, I anticipate ongoing discussions about flaring. However, I don't have a specific perspective on where that regulation may head at this moment. Chuck, do you have anything to add?

Yes, what I would add regarding North Dakota is that the interested stakeholders there, including the state, producers, and processors, have been meeting fairly regularly over the past two quarters. They are examining the current flaring rules and flaring exemptions, exploring how they can collaborate more closely to reduce flaring. There are discussions about potentially modifying some of these rules in the future, but nothing has been finalized yet.

Michael, I want to make a brief comment before following up. The Texas report indicates that pressure on producers regarding flaring is likely to increase. This situation presents opportunities for midstream companies. We can expect to see enhanced infrastructure development aimed at reducing flaring. By optimizing the throughput from rich gas, we will generate more NGLs from the basin sooner rather than later. The Texas Railroad Commission has acknowledged the flaring issue, and they've taken a unique perspective on its intensity, highlighting the need for action. Regulators will need to address this, with midstream playing a significant role in the solution.

Got it. And then...

Michael, I want to make a quick comment. The recent Texas report highlights that producers will face increased pressure regarding flaring. This situation presents opportunities for midstream companies. Specifically, we are likely to see an increase in infrastructure development to mitigate flaring. By optimizing the throughput of rich gas, we can expect more NGLs to be produced from the basin in the near future. The first step in this process was the Texas Railroad Commission recognizing the issue. They provided a fresh perspective on the flaring intensity, clearly indicating the need for action. Regulators must address this, and midstream will play a significant role in the solution.

In response to the second part of your question, as our debt decreases to the levels I mentioned, we will have many options available to us, whether it involves share buybacks, dividends, or other strategies. The important thing is that we will have the flexibility to take the appropriate actions at that time. As for the dock...

And Craig, this is Kevin. Regarding the dock, we still see it as an important part of our business, although it’s not essential. We have a dedicated team working hard on it and are confident that our barrels will continue to clear. While we don’t have direct price exposure to assess the true value of prices on the Gulf Coast, we’ll keep pursuing this opportunity. We have numerous discussions globally with potential customers and are also engaging with Gulf Coast partners about dock opportunities. We will continue our efforts and will announce something once everything is aligned.

Craig, let me add a follow-up comment to Walt's remarks. The company has always managed the balance sheet prudently, with a focus on maintaining an investment-grade status. If there's one principle we adhere to, it is this. As we look to the long term, the company will continue to take actions that are sensible and responsible, and we have a strong track record of doing so. This is a key point to remember. That concludes my remarks.

Our quiet period for the first quarter starts when we close our books in early April and extends until we release earnings in late April. We'll provide details for that conference call at a later date. Again, thank you all for joining us, and the IR team will be available throughout the day for your questions. Have a good rest of your day. Thank you.