Williams Cos Inc (WMB) — Q1 2017 Earnings Call Transcript

Thanks, Amy. Good morning and thank you for your interest in Williams and Williams Partners. Yesterday afternoon, we released our financial results and posted several important items on our website. These items include press releases and related investor materials, including the slide deck that our President and CEO, Alan Armstrong, will speak to momentarily. Joining us today is our CFO, Don Chappel; and our Chief Operating Officer, Michael Dunn. We also have the leaders of our operating areas on as well. 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 various non-GAAP measures that we reconcile with Generally Accepted Accounting Principles, and these reconciliation schedules appear at the back of today's presentation material. So with that, I will turn it over to Alan Armstrong.

Great, thank you, John, and good morning, everyone. Glad you could join us today. I plan to keep my remarks brief to allow as much time as possible for your individual questions and also recognizing we have our Analyst Day coming up next week on May 11 in New York City. The first quarter of 2017 demonstrated the resilience of our business as we continued to show meaningful growth and stayed on track for our 2017 guidance, despite the impact of some significant third-party outages and production freeze-offs in the Rockies. Our natural gas-focused strategy continues to be on track as we differentiate ourselves by delivering consistent and sustainable growth on the back of low-cost natural gas demand. Overall, I'm pleased with this quarter's progress. So let's get started on Slide 2 and take a look at our first quarter. Starting with WPZ's GAAP results, we saw a sharp increase in net income due to higher investing income on the Permian for Marcellus transaction that we completed in the first quarter. Apart from the increase due to this transaction, our ongoing business performed very well, generating an increase in operating income of $141 million compared to the first quarter of 2016. Moving now to adjusted EBITDA and DCF, WPZ's adjusted EBITDA grew over 5% compared to the first quarter of 2016, marking 14 consecutive quarters that we generated year-over-year growth in this measure. We delivered $752 million in DCF for the quarter, which was also up over the first quarter of 2016 and provided a strong coverage ratio at Williams Partners of 1.33. Now let's take a look at how each of the segments performed versus last year. First of all, the Atlantic-Gulf delivered another solid quarter. Adjusted EBITDA increased by $48 million or almost 12% over the first quarter of 2016, reaching up to $453 million for the quarter. There were a couple of third-party incidents on adjacent pipelines near Paradis, Louisiana, and Corpus Christi, Texas, that impacted our results, although there was no direct damage to our facilities from these incidents. Despite this, Atlantic-Gulf increased fee-based revenues by about $43 million for the quarter, primarily driven by new projects that we brought online in 2016. Our Gulf Trace project was put in service during the first quarter of 2017, contributing fee-based revenues here in the first quarter of nearly $9 million. Let's move on to the West segment, which now includes the predictable Northwest Pipeline system and existing Rockies G&P assets to which we've now added the Conway and Overland Pass Pipeline, as well as large-scale gathering systems previously located within our Central Operating Area. The broad-based portfolio underpinning the West, along with a sharp focus on cost control, delivered stable first-quarter adjusted EBITDA compared to 2016. Overall, the West adjusted EBITDA came in within 3% of the first quarter of 2016. We did see lower fee-based revenues, mainly as a result of contract changes and 21% lower volumes in the Barnett area. The Barnett field was impacted by little to no production spending by our previous customers there over the last year. We're excited to see the impact that the new operator in the area, Total, with a $40 million-plus annual investment will have in restoring this production. Despite a mild winter throughout most of the U.S., the West experienced extreme weather in January, causing widespread production freeze-offs in the Rockies. We have seen a good rebound in volumes as things have thawed and several rigs have returned to the area. Our overall volumes in the West are tracking 2.4% higher than the average during the first quarter of 2017. We experienced record throughput volumes on Northwest Pipeline due to the cold weather in the West. In the Northeast G&P, year-over-year operated gathering volumes were up nearly 5%, with adjusted EBITDA increasing $2 million to $227 million compared to the same period last year. We're also seeing a pickup in well-connect requests across most of the Northeast as producers prepare for takeaway capacity coming online. I'd like to make a few comments about our NGL & Petchem business. The first quarter saw overall improvement in prices and margins for propylene and ethylene, although the results were offset by lower production volumes, primarily due to an unexpected failure on the local utility provider system on March 12, which caused a shutdown of our Geismar plant. This transaction is one of the last components of de-risking Williams' revenues from direct commodity exposure. We're continuing to work on the remaining regulatory approvals for the Atlantic Sunrise project, and just this week, we updated the final permitting data required for the PA DEP 102 state permit and the PA DEP 105 permit. We submitted an application for a FERC certificate for our Northeast Supply Enhancement project, a nearly $1 billion fully contracted project that will increase the supply of natural gas to the New York City area by about 400 million a day. We saw records on two of our major interstate pipeline systems, Transco and Northwest Pipeline, during the quarter. We also achieved a quarterly gathering record of about 6.9 Bcf a day in the Northeast G&P. We closed on the Permian for Marcellus transaction, bringing our Bradford Supply Hub average ownership to about 66%. As evidence of the increasing focus on predictable fee-based revenues, we announced an agreement to sell the Geismar olefin facility for $2.1 billion to NOVA Chemicals, which is expected to close this summer. We'll also be introducing our new Chief Operating Officer, Michael Dunn, during our Analyst Day next Thursday, May 11. We look forward to talking to you about the significant opportunities ahead for Williams and how our competitively advantaged asset base is well-positioned to deliver sustained growth. That concludes my prepared remarks. Now, I'd like to pass it over to the operator.

Good morning. This is Charlie in for Jeremy. Just wanted to follow up on the Atlantic Sunrise. I know you said you're in the midst of getting the second state-level permit. Were there any other requirements there? I remember there being one from the Corps of Engineers. Additionally, could you provide clarity on the growth CapEx guidance, $2.1 billion to $2.8 billion? Can you remind us what might cause us to hit the upper end or lower end of that guidance range?

Yes, sure. I'll have Mike Dunn take that permitting question in a minute. Regarding the capital, the primary variances are the timing of the Atlantic Sunrise project and how soon we're able to start. The timing of Northeast construction and the gathering systems feeding into that are also variable. So it really depends on the timing of these projects rather than the number of projects. Mike, can you take the Atlantic question?

Sure. Thanks, Alan. Good morning. We have a 404 permit update to provide to the Corps of Engineers that will occur later this month. That's similar to the PA DEP updates that we're providing to Pennsylvania. We expect permit receipts from both PA DEP and the Corps of Engineers in July, assuming everything goes well.

Great. Thanks. Just one more quick question on G&P volumes in the Northeast. Can you provide additional details regarding the Utica volumes that caused the shift to more dry gas exposure?

Yes, I’ll have Jim Scheel address that portion.

Chesapeake has moved rigs out of the Utica, specifically in the Cardinal wet gas area, over the last couple of years. We've seen natural declines that have dropped us from a high of about 1 Bcf a day to just under 700 Mcf as we move into the first quarter. However, we anticipate volumes ramping up as Chesapeake is moving in additional rigs. Some of the reduction in wet-side volumes has been offset by new drilling in the dry Utica.

Great. Thank you.

Thank you.

Good morning, everyone.

Good morning.

I wanted to start in Marcellus. We've seen a competitor JV with a producer for some processing plants. On your acreage, we've seen one producer acquire three or four of your customers and may want to partner in processing. Is this something you'd be interested in? How do you evaluate whether to get an upfront volume commitment on your processing plants in exchange for acreage leases versus taking on more risk?

Yes, we're always happy to work with customers that have valuable contributions to make. We're excited to see increased development in the OVM area, receiving considerable well-connect requests, which have come in faster than we anticipated. Our processing capacity in the OVM is very valuable, and we want to maximize that in any transaction. We're enthusiastic about the activity underway in the area.

Okay. And then moving over to Barnett, there's talk about directing stack gas volumes to excess capacity at Barnett plants. Is this an opportunity for you, or are there contractual impediments?

We don't have any processing capacity in the Barnett. We only have gathering, compression and a dehy system. Unfortunately, we're not positioned to take advantage in the Barnett.

Okay. And then last one, have you disclosed how much capacity and how long the long-term contract is with NOVA?

No, we haven't disclosed that yet. We'll provide more detail at our Analyst Day. I do think we've indicated it will be for the full requirements of the plant, historically around 50,000 to 55,000 barrels a day, depending on production and whether we're cracking ethane or propane.

Okay. And what's the capacity of the line? It seems like there's an expansion set for the second half of the year.

That depends on the incoming ethane. We have points supplying ethane from multiple locations, so the capacity is contingent on where that production derives. We've completed a significant expansion earlier this year, positioning us well for future supply.

Thanks. I wanted to start with Northeast Supply Enhancement, at $1 billion of CapEx. Are the returns similar to what you have guided on other projects? Moreover, what's the expected in-service date?

Rory, would you like to address that?

Yes, I would say the returns fall within that same range. In terms of in-service, yes, we think it will be 2020, but as usual, we're trying to exceed that target.

Great. Regarding your Southeastern Trail open season, can you elaborate on what that entails? How do we view that relative to existing contracts or revenue uplifts?

This capacity could either be latent in the system or involve new facilities to offer capacity. We're in the process of evaluating requests that have exceeded our capability to offer. Resolving efficiency and capacity will dictate the deals closed.

Awesome. On multi-year guidance, I know you used to provide that, but is there room for a preview of what we should look for at the Analyst Day?

While we won't provide specific guidance, you'll see drivers of growth from our operational leads, particularly regarding volumes and EBITDA in the Northeast. We'll clarify growth opportunities along the Transco system and cover growth drivers into 2018. Our focus will be offering transparency on drivers while enabling your assessments.

Hi. Good morning. I wanted clarity on the Geismar feedstock agreement. Are there differences compared to previous practices? What's the anticipated cash flow uplift from it?

It’s a complex answer. Previously, costs and revenues were less transparent due to their relationship with Geismar's margin. We're expecting a modest uplift in revenues from this transaction, and it will now be recognized as third-party fee-based revenue directly affecting the bottom line.

Got it. Moving to the consolidated debt-to-EBITDA forecast by year-end, what can you share?

We don't have an update at this time, but it's decreasing. We indicated that proceeds from the Geismar sale will cover the $850 million term loan and pre-fund remaining CapEx. We will provide additional insights next week.

Understood. Can you update us on the legal matters, especially with Energy Transfer and Constitution?

The ETE discussion had a hearing on the discovery process two weeks ago. The judge is reviewing the situation further. For Constitution, we’re in discussion with the administration and are optimistic about it. There's considerable support for the project, with unions backing it, and we're pushing ahead.

But no date on the Constitution appeal conclusion?

None set yet, though we expect it won’t take too long if things progress as we anticipate.

Good morning.

Good morning.

Regarding the long-term feedstock agreement and potential pipeline sale during the Geismar divestiture, can you discuss the rationale for retaining the asset and the expected tax and long-term benefits?

It's positive for us. We're excited about this transaction because it provides reliable, long-term fee-based revenues. Retaining it was a strategic decision to maintain stability for revenue. We have other customers on the system that we anticipate will expand, and we want to grow along with them.

For the quarterly impact from third-party outages affecting discovery in Markham, can you estimate the EBITDA effect?

We're not disclosing that explicitly. The outages significantly impacted our revenues on Discovery, which affected throughput from the Eagle Ford volumes. We had significant downtime, losing volumes.

Hi, good morning. You mentioned there were positive weather impacts on the Northwest Pipeline's throughput for the quarter. How should we view that for the rest of the year? What updates can you provide regarding longer-dated projects in that region?

While fully contracted pipelines see minimal variability, we did notice slight uplift in IT revenues. Our Northwest Pipeline volumes are up, indicating demand growth, aligning with expansion incentive. I'm going to turn it over to Walt for specifics on long-term projects.

We are pursuing two projects on Northwest Pipeline that are aimed at increasing lateral capacity to serve customers, generating incremental lateral fees. We expect to provide more details at Analyst Day.

Great, thanks for that. I had a broader question regarding Geismar transaction implications for distribution growth outlook and dividend consideration.

As we continue to execute, it may help position us to meet the higher distribution growth guidance. We will focus first on reducing revolver debt, and then determine the best use of excess cash towards the end of the year.

Hi, just a couple of questions. Regarding the competitive nature of Marcellus amidst approaching gas from the Permian. Do you think the basis will contract, and how do you see this impacting your growth pathways?

With pipeline relief underway, Marcellus stands as the only supply capable of meeting growing demand. Its reliability will maintain its position in the market as buyers continue to require low-cost supplies.

Cool. Could you update how well your offshore investments are performing this year?

Our Keathley Canyon Connector is operating fully loaded, while Gulfstar field troubles are easing, and volumes are starting to line out successfully. We're optimistic about performance this year in the Eastern Gulf.

Hey, guys. Quick question regarding the Powder River Basin development. Any ideas about its trajectory moving forward?

We're seeing a renewal of interest and expect to see new well developments and upper-level demand with a couple of rigs returning that had been inactive in recent years.

Perfect. And regarding Gulf Trace, can you discuss current pipe or labor cost inflation expectations going forward?

Although inflation pressure can arise with some larger projects, we're confident in our team's ability to manage costs effectively.

Thank you all for joining today. We're excited about how our team is executing and optimistic about future prospects. We look forward to our discussion next week.