Williams Cos Inc (WMB) — Q4 2017 Earnings Call Transcript

Thanks, Chris. 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 a slide deck that our President and CEO, Alan Armstrong, will speak to you momentarily. Joining us today is our Chief Operating Officer, Michael Dunn; and our CFO, John Chandler. 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 reconciled to Generally Accepted Accounting Principles. And these reconciliation schedules appear at the back of today's presentation materials. And so, with that, I'll turn it over to Alan Armstrong.

Great. Good morning, everyone, and thank you, John. First of all, I'll just say these are going to be a little longer comments than usual, just because there are a lot of issues that we want to discuss this morning, so I'm going to jump right in. I'm going to begin by saying how pleased I am with the organization's strong execution in 2017. A lot of notable achievements. We safely and in a timely manner delivered on Transco's Big 5 projects, which was Gulf Trace, Hillabee Phase 1, Dalton, New York Bay, and the Virginia Southside II. We exceeded the midpoint of our guidance range for adjusted EBITDA and actually exceeded the top end of the range for distributable cash flow and cash coverage ratios. Finally, we were able to bring CapEx spending in slightly below the midpoint of the range. Our teams achieved these impressive results, which include improvement in year-over-year adjusted EBITDA for both the fourth quarter and the full-year 2017 despite the impact of Hurricanes Harvey, Irma, and Nate and while executing crisply on $2.3 billion in asset sales. If you go back to September 2016, it's actually $3.3 billion in asset sales. As you'll recall, a strong foundation was laid with the financial repositioning we executed in January of 2017, which positioned the company to fund our attractive slate of fully contracted, large-scale expansion projects without the need to access public equity markets for projects included in our current forecast. Now, we're providing further insight into 2018, where we look forward to a full-year revenue contribution from our Big 5, as well as contributions from our Atlantic Sunrise project, when it is placed online later this year, along with the associated growth in the Northeast gathering volumes upstream of that. We are as excited as ever about our opportunities across the asset base, which we see driving continued growth for 2019 and beyond. For today's relatively long call, we're going to hit a recap of our performance for fourth quarter and full-year 2017; we're going to hit the 2018 financial guidance; and we're going to take a brief look at the types of opportunities we see driving our growth into 2019 and beyond. To remind you, we are planning an Analyst Day event in May, where we'll dive deeper into our growth drivers for the future. Moving on to slide 2 and review the fourth quarter. According to our GAAP results, which included some large onetime events related to the recent federal income tax reform, Williams' C-Corp level reported fourth quarter net income of more than $1.6 billion, a $1.7 billion improvement from fourth quarter 2016. This large improvement was driven primarily by the re-measurement of Williams' deferred tax liabilities to reflect anticipated lower future tax payments. This resulted in a $1.9 billion gain at the GAAP level. But it's not quite that simple when it comes to the impact of Tax Reform, as we also had to take a $713 million non-cash charge at WPZ related to Tax Reform for Transco and Northwest Pipeline. I'll go further into the Tax Reform impact on the regulated pipelines a bit later. For now, I'll just say that, generally speaking, we had to book an estimated regulatory liability of $713 million for possible future impacts on our cost-of-service rates resulting from this Tax Reform bill. Even though this is a big number, it's likely to only affect our future actual cost-of-service rate case calculations by relatively small annual amounts, as it gets spread over a period that could be 20 years or more and is one of the many variables that impact the ultimate rates that we charge for our max rate tariff service. At this point, given higher integrity expenses and maintenance capital expenses at Transco, we still expect to file a rate increase on our cost-of-service rates, even after taking into account the effect of this change in the tax liability. Let's move to the performance of the business in the fourth quarter where WPZ's adjusted EBITDA was up $84 million, or 8% when you exclude the NGL/Petchem businesses that we've sold. This increase was driven mostly by our more than $100 million increase in fee-based revenues, which came primarily in the Atlantic-Gulf and our West segments. With that, let's move on to slide 3 to look at the full year of 2017. Even for the full year, those large fourth quarter Tax Reform related items played a key role for the GAAP results, but there were a few other drivers, including about $1.3 billion in gains we had on the Geismar and Permian JV sales. Looking at adjusted EBITDA, WPZ was up over $200 million or about 5% versus 2016, when you exclude the former NGL/Petchem businesses that we sold. In the graph, you can see where all three of the segments show improvement for the full year. Atlantic-Gulf saw increased adjusted EBITDA driven by the Transco expansion projects and increased volumes in the Eastern Gulf, partially offset by higher O&M expenses as we continue to do quite a bit of asset integrity work and hydro testing on the main lines along the Transco system. For the full year of 2017, results for the West benefited from lower cost, growth in basins like the Haynesville, and higher commodity margins that were partially offset by the loss of results from the sell and trade of our DBJV trade with Western Gas and Anadarko. The Northeast realized added benefits from the growth in the Bradford area with increased ownership from the various Bradford County systems that came with that trade I just mentioned. Positive results on our Susquehanna and Ohio River systems were offset by lower volumes in the rich Utica and our non-operated interest in the UEOM joint venture. In the rich Utica area, we continue to see declines. You recall we own both a rich gas gathering system and then we own a 62% interest in a non-operated interest in UEOM up there. In the Northeast, we've consistently spoken of 2017 and 2018 as transitional years for Northeast volumes. During 2017, we started to see step changes in takeaway capacity in the Southwest part of the play that are beginning to unlock the growth potential of these unmatched natural gas reserves. Of course, we've also seen a lift in NGL prices in that area that's really spurred a lot of drilling in the Southwestern part of the rich Marcellus play. Moving on to slide 4. Here, we've recapped some of our recent achievements as we continue to build long-term sustainable growth in the business. It certainly was an impressive quarter and full year for the Transco team. The Big 5 projects that we've referenced many times added approximately 25% pipeline capacity to Transco, which is quite significant given the size of the Transco to start with. The final two of the Big 5 projects, New York Bay and Virginia Southside, were placed into service as planned in the fourth quarter. Also in the fourth quarter, our West team saw higher volumes in 8 of the 10 gathering franchises, led by continued growth in the Haynesville. In the Northeast, our exit rate gathering volumes were up by 600 million a day or 9% over 2016, as the debottlenecking of the Northeast is just getting started. A portion of this volume growth is contributing to higher utilization of our Ohio Valley midstream processing capacity, where we now expect to expand that facility by an additional 400 million a day, supported by strong customer volume commitments and driven by this continued rich Marcellus drilling activity. We've already seen the impact of the five major projects this year, which added over 2.8 Bcf a day of new capacity. This new capacity enabled Transco to set one-day and three-day delivery records in January. All of this is before we realized the benefits of the most significant expansion in Transco's history, the Atlantic Sunrise project, which continues to make great progress. We faced a challenging winter on the Atlantic Sunrise project, but a tremendous effort by our team managing the many contractors involved has kept this project on track, and importantly, in compliance with the many environmental regulations controls required up there. Certainly, this has been no easy task for the team. But today, we are greater than 30% complete on the pipeline segment, and importantly, greater than 40% complete on the compressor station. The difficult winter conditions up there have led the team to work hard, particularly paying attention to the permitting requirements that are on us up there. We are targeting a July start-up for the mainline portion, with the greenfield compression likely taking a few months longer than that. Our LNG-related story continues as well; the Gulf Connector has begun construction. We're targeting the first quarter of 2019 for the in-service date for this 475 million a day addition to our Gulf Coast LNG delivery system. We've built out quite a delivery system along the Gulf Coast, being able to serve all the growing LNG, and Gulf Connector will be the second big addition to that. We also made the FERC certificate application on the Gateway, a project that recently moved from the potential project list to full execution. We continue to look at the potential to enhance Southeastern Trail. We do have a binding shipper commitment that makes a very attractive project for us on a standalone basis, but we are hoping to combine this with other customer needs to make another significant large-scale and strategic expansion on Transco that would be right on the heels of the Atlantic Sunrise expansion. Turning to the West, you may remember we spoke about the Chain Lake expansion in Wyoming during our third quarter call. Today, I'm pleased to update that we placed an additional Chain Lake expansion project into service in January, as we continue to add volumes on our Wamsutter system in Wyoming. All in all, a great quarter with significant accomplishments across a variety of fronts. So, let's move on to slide 5. I'm not going to spend too long on this slide, but it's an important and notable wrap-up reference regarding our 2017 performance versus guidance. All good news here with beats on all our key performance metrics and great progress on our leverage metrics as well. We continue to deliver not only on our operational metrics, but on our financial objectives as well. One thing I'd like to note here relative to debt: our actual net debt to adjusted EBITDA came in well below guidance. On PZ, it came in about 3.5x; and on WMB at about 4.4x, which is well below what we were targeting. You need to add about 0.3 or 0.4 to the actual number when estimating the rating agency calculation. If you do that, this gets you up to about a 3.85 ratio on PZ and about a 4.75 at WMB on a consolidated basis. Just to be clear on that, we're excited about that, and certainly, we achieved better than we were hoping for the year. I would remind you that we will see that creep up a bit here in 2018 as spending wraps up on Atlantic Sunrise, ahead of the full cash flow coming on. Then we expect that to come right back down as those cash flows come on. Overall, really great news on the credit metrics, and we'll continue to drive our strength in our balance sheet. Let's move on to slide 6 and take a look at our 2018 financial guidance. There will likely be some surprises at our adjusted EBITDA range, which has a midpoint of $4.55 billion. However, as we'll see on the next slide, our year-to-year comparison on guidance has recently been hit by about $150 million of unusual noncash items that are driven by how regulatory accounting practices treat the new lower taxes and new GAAP revenue recognition standards that were applied to some amortized cash flows. Neither of these items impacts actual cash we will receive from customers in 2018, so I want to stress that this really is driven by these accounting practices. Our base businesses look set to deliver guidance of about $4.7 billion prior to these items, representing a $300 million increase or about 7% on an apples-to-apples basis. So, what's this $150 million of noncash items about? The new GAAP revenue recognition rules require us to spread out some of our deferred revenue for contracts that we've already received payment on over about 10 years longer than the old rules, which dropped the 2018 adjusted EBITDA by about $120 million. Also, we saw about $30 million in 2018 Tax Reform impact. Most of that comes from Northwest Pipeline via regulatory accounting charges due to the Tax Reform, even though the revenues we receive from our customers won't change during this current rate cycle. Moving to DCF, we have a range of $2.9 million to $3.2 billion, and the midpoint of the range represents an 8% growth over 2017. Our dividend and distribution growth rates, related cash coverage, and leverage metrics are all consistent with the guidance we provided this time last year. A year later out, we believe these growth rates will continue as we look out over the next two years. You will also note more specificity on the timing of growth through the year. At WPZ, we expect to increase distributions each quarter, so those will be quarterly raises. At WMB, we expect to raise the dividend just on an annual basis. To be clear on that front, we'll be recommending a 13% dividend increase to be paid in March to the WMB board here in the near future with the same dividend level being recommended for June, September, and December, resulting in this 13% increase at WMB, which comes in slightly above the midpoint from our guided growth rate last year. We expect the WPZ raise to be right in the middle of the range of that 5% to 7% range that we talked about last year. We expect to maintain strong coverage at both WPZ and WMB, and the leverage metrics will remain at healthy levels, although we do expect the levels, as I've just mentioned, to rise a little bit as we spend on Atlantic Sunrise here in the near term. Coverage at WMB of approximately $100 million per quarter will be used to continue paying down the WMB revolver here in the first part of the year, and we continue to evaluate the best use of that excess cash flow at WMB post the revolver paydown, which will come in the second half of the year. Now, let's take a closer look at that buildup for 2018 adjusted EBITDA now on slide 7. First of all, beginning with the big pieces. By virtue of our sell of the Geismar olefins facility in July of 2017, you can see the $72 million step down there. That's just the EBITDA associated with that business. We expect a solid $300 million increase from our continuing businesses with significant growth driven by Transco's expansion projects, partially offset by the loss of the Hadrian volumes on Discovery. We also expect strong growth in volumes and EBITDA out of our Northeast G&P business. Susquehanna Supply Hub is poised to make significant contributions as expansion work currently underway will wrap up in the first quarter. The end service of Atlantic Sunrise will lead to significant volume growth at both the Susquehanna and Bradford County systems, but we are not counting on this until the later part of 2018. Recently, executed contracts combined with new business we are currently finalizing will contribute to very strong Ohio River Supply Hub growth. The continued growth in our business and asset integrity work is leading to modestly higher operating expenses in 2018, as you can see. To wrap it up, $300 million of adjusted EBITDA, which is approximately a 7% growth rate year-over-year when comparing results from the continuing businesses leads us to about a $4.7 billion EBITDA before the impacts of these non-cash new GAAP revenue recognition and Tax Reform impacts. As I discussed earlier, the key impact of the new accounting standard was to spread out the recognition of the prepayments we received in 2016 associated with Barnett and Mid-Con contract restructuring. If you recall, those were on gathering contracts that we had with Chesapeake that now primarily are Total contracts and reducing revenue recognized in 2018 and 2019 but increasing revenue recognized beyond 2019 versus what we expected on the old accounting standard. If you'll recall, it really was just driven by the fact the period of the MVC was the period that we were amortizing that period over the new accounting standards, requiring us to smooth that out over the entire life of the contract, not just the period that had the MVC impact. The impact on 2018 is about $120 million, less revenue being recognized under the current standard than we would have recognized operating under the old standard. We want to get in the habit of providing multi-year guidance; however, we do expect an even stronger level of growth in 2019, particularly in Northeast G&P, and, of course, on Transco. Given the timing around Atlantic Sunrise and the significance of that project as well as other projects we brought on in 2017 and 2018, we thought it would be helpful to give you at least a glimpse here into what we expect coming off of Transco into 2019. So, let's move on to slide 8 and take a closer look at how Transco's adjusted EBITDA is growing over the next couple of years. Growth in Transco will be driven by negotiated rate expansion projects, and there is strong growth coming in the future. Let's begin with the impact of a full year of revenue from the 2017 Big 5 projects. Note that in 2017, we only had $140 million partial year impact of the Big 5 projects that were placed in service during the year. In 2018, on top of that $140 million, we'll see an incremental $110 million. In 2017, we did have a significant step up in expenses, primarily due to necessary pipeline integrity and maintenance programs. We prioritized safe operations and proper maintenance, which is reflected in the costs you see in our results for 2017. In 2018, you can see the full $250 million impact of the Big 5 when you add the $140 million partial year and $110 million contribution in 2019. You can also view the impact of Atlantic Sunrise and Garden State here in 2018 with a partial-year contribution of $140 million after implementation in 2018, which we also expect to see a significant increase in 2019. So, as you can see, these are some of the drivers. First of all, the effect of a full-year revenue from Atlantic Sunrise is captured here, with a full-year impact of $425 million in EBITDA resulting from a $285 million increase in 2019 on top of the $140 million contribution in 2018. Transco is also working on its next rate case. There is a high interest in this topic, particularly with the recently enacted Tax Reform law. I wanted to discuss the process as well. First, I want everyone to understand that the negotiated rate contracts Transco has are not subject to change with this rate case. Tax Reform will have no impact on these contracts. Those are firm fixed contracts, and both parties agree on a fixed rate on the front end for the term of those contracts. Most of our major expansions are covered by negotiated rate contracts. By the time Atlantic Sunrise is in service, we expect Transco to be comprised of roughly 50% negotiated rates and 50% cost-of-service-based rates. It's the cost-of-service-based rates that are subject to changes with each of Transco's rate cases. Timing-wise, we expect to make our initial rate filing in August, and we expect the revenue impact of new cost-of-service rates to be primarily a 2019 event. I want to discuss factors that affect the actual value of a new cost-of-service rate. Operating expenses are intended to be recovered in the cost-of-service rates. For example, the increased expenses we incur on Transco from pipeline integrity and reliability improvements will be accounted for and recovered in our next round of cost-of-service rates. We have considerable work to ensure system safety, and you do see that cost continuing for some time. The maintenance capital spent on Transco goes directly into the rate base, and Transco will earn a return on that capital. These items would work to push our cost-of-service rates up from where they stand today. The Tax Reform Act has also generated lower corporate tax rates, which will also be a factor. There are two primary ways that the lower corporate tax rates will impact the pipeline's rates. First, simply put, the lower cost that lower tax rates represent—a provision in our rates for current and future taxes will be lower; now that corporate tax rates decreased, that is factored in. The second impact is this non-cash regulatory charge and related regulatory liability you saw when we discussed the fourth quarter results earlier in the call. This liability represents an estimate of the value returned to shippers to account for the deferred portion of income tax provisions we've collected in the past on Transco's rates. This liability will be amortized off of Transco's books and realized by cost-of-service shippers over an extended period of time, which could be as long as 20 years or even more. The rate-making process on Transco for the cost-of-service contracts will likely be a negotiation that considers all of these factors as we jointly determine the fair cost-of-service rates for our max rate tariffs. In summary, considering all of these items, along with other impacts to the cost-of-service model, Transco does still expect to file for an increased cost-of-service rate in our upcoming August 2018 rate filing. Now, moving on to slide 9. We've shown that we have impressive growth in the next couple of years, largely from long-term fully contracted and fixed-rate demand charges on a regulated pipeline, and the expected pull-through under our existing gathering contracts. Beyond these near-term growth drivers, our natural gas-focused strategy and competitively positioned assets will likely capture even more growth in 2019 and beyond. Importantly, Transco's fully contracted growth doesn't end with Atlantic Sunrise. We have a committed backlog of seven fully contracted projects that will go into service in 2019 and beyond, currently led by our largest of these, the Northeast Supply Enhancement project with commitments from subsidiaries of National Grid. We've applied for the FERC certificate, and the FERC is currently working on the environmental impact statement. We are targeting a late 2019 in-service date for the project. Consistent with past practice, we include some additional time when forecasting revenue and EBITDA growth into our future business plans. Beyond these fully committed projects, I want to update you on the large portfolio of potential interstate transmission opportunities we are pursuing. At our 2017 Analyst Day, we discussed about 20 projects we were pursuing at that time. Since that time, three of these 20 projects have moved out of this bucket and moved from potential to customer committed, so we made great progress on those projects. Rivervale South to Market and the Gateway project have moved into full execution with the FERC certificate application filed. Additionally, the Southeastern Trail project now has binding customer commitment. New opportunities continue to emerge, and, in fact, the potential project list has now been backfilled and now stands at over 20 projects. Moving to the Northeast Pipeline infrastructure build-out, we'll continue to unleash the gas reserves in the Marcellus and the Utica. Based on our customer commitments and new activity, we now expect to expand our Ohio Valley Midstream processing capacity, which includes the Fort Beeler processing facility or complex as well as the Oak Grove complex. We expect that combined capacity to increase by 400 million a day, which will take us to over 1.1 Bcf a day on that processing complex. We also have discussions underway for a sixth major expansion of the Susquehanna Supply Hub. We expect to complete the fifth expansion this quarter. In the Deepwater Gulf of Mexico, we are also seeing great growth opportunities, especially in 2020 and beyond. Modifications to our Eastern Gulf assets to serve the new dedicated volumes from Shell's major Norphlet play are under construction, and we are well underway with that. Shell has been reimbursing us for those modifications. We are excited about seeing the impact of that in 2020. Our recent announcements from Shell on their Whale prospect and Chevron on their Ballymore prospect are also exciting. The Whale prospect is within 15 miles of our Perdido oil and gas export pipeline, leading to Shell's Perdido facility. The Ballymore prospect is within 3 miles of Chevron's Blind Faith platform, where our Mountaineer oil pipeline and our Canyon Chief gas pipeline already serve Chevron in these areas. We expect both of these major discoveries to drive significant free cash flow increases in 2020 and beyond. Finds like Ballymore and Whale indicate that Deepwater developments remain highly commercial. Williams is in the right position in both the Eastern and Western Gulf to benefit. Additionally, drilling activity in Wyoming is driving growth in our gathering and processing volumes in both the Wamsutter and the Niobrara field. Following up on the two Chain Lake expansions I mentioned earlier, another expansion opportunity in Wamsutter is emerging for a customer in this play. We continue to see significant activity in the Wamsutter field. We also see volume growth in the Eagle Ford and Haynesville. This activity demonstrates the value of our strategy to be in the right spots in the best basins, and to be a large-scale competitive player in all of our basins. We see very attractive long-run return on capital from our Western gathering and processing footprint. The return on invested capital will be extended by the latest round of customer activity. I'll wrap it up here. Williams is committed to executing the plans laid out for our shareholders and customers and expanding our business in a manner that generates sustainable shareholder value. The result of strong execution in 2017 included generating healthy cash coverage that supports investments in our attractive portfolio of growth projects, while significantly strengthening our balance sheet. Williams realized a $3.3 billion reduction in consolidated net debt during the year. Through disciplined capital investing, we drove an important improvement in our return on capital employed, which has become a key focus from the management team and that was driven by the board. That's front and center in our decisions as we look at our business. As we look ahead to our plans to expand the business, I want to reiterate that Williams has achieved full self-funding. We do not need to issue any public equity at WMB or at PZ to fund our stated forecasted capital projects through our full planning horizon. We're able to do this while maintaining a strong balance sheet, leverage metrics, and healthy coverage for both WPZ distributions and WMB dividends. WMB shareholders are positioned to benefit from a $1.9 billion reduction in deferred tax liabilities, which will manifest through an extended period of cash tax deferral. Williams does not expect to be a cash federal income taxpayer through at least 2021, potentially longer, depending on future capital spending opportunities. We'll experience much lower taxes being paid when that deferral period does ultimately end. We're excited about where we are with the company today. We're excited about where we're going. We believe we are extremely well-positioned financially. We've got the operating capabilities that we need. Strategically, we're positioned better than anybody in the space regarding taking advantage of the low-cost natural gas reserves that continue to expand and grow demand in both U.S. and international markets. I thank you for your time today. I'll turn it over to the operator for our first question.

Good morning.

Good morning.

I want to start off with Northeast gathering and processing there. The O&M had stepped up a bit quarter-over-quarter there. I was wondering if you could dive in a bit more on some of the drivers there. Expanding on the segment in general, could you just refresh us on activity rig count in your area and what gives you the confidence regarding growth into 2018?

Good morning. This is Michael Dunn. I'll take that question. From an enterprise perspective, we look at improvements in our operating margin across our entire enterprise in each operating area. We drill that down to the franchise level within each operating area. So we set goals for the organization to improve those targets on our operating margin. In the Northeast specifically, we are seeing significant growth, adding several facilities, whether it be compression or pipeline facilities with increased employees and operating costs. We are seeing strong growth in our revenues up there, and correspondingly with that growth, we are seeing an increase in our cost. Specifically, in the Northeast, we saw new compression facilities come online and additional electric costs. We had emergent work in West Virginia dealing with longwall coal mines that require us to manage pipelines that run above them to avoid operational issues. We know where these issues occur and work with the coal mine companies. This does increase our expense, alongside avoiding impacts from land movement in primarily West Virginia. There were also some emergent overhauls at our Fort Beeler facility that were unanticipated. We did have a pension lump sum settlement that lowered our GAAP numbers, but these affected us. Overall, we are seeing growth that drives costs higher, but we monitor operating margins closely and have set goals for our teams to meet or beat their objectives. Regarding rig counts, we are seeing improvement as producers anticipate Atlantic Sunrise online and drilling activity in response. The additional takeaway capacity from third parties in the Marcellus is driving production growth for us as well. Our Oak Grove expansion exemplifies that.

Great. Thanks. Just touching on Southwestern, if you could update us on how the ramp progressed during the quarter and how you see that going into 2018?

This is Alan. In the Southwest Marcellus area, Southwestern has been very active. We signed a contract with them last year, and the way that contract works, they inform us ahead of time when they intend to bring on new volumes. Our capacity for them on processing expands along with their minimum volume commitment, which stands behind investments we make. We have seen their requests for service increasing quickly, leading to considerable growth, with activity connecting new pads. We are thrilled to have them as a customer.

Got you. Great. One last one on Discovery, could you provide a bit more color on your outlook and ability to redeploy or gain more business there?

Sure. The Hadrian field, which was a large gas-only field coming across Anadarko's Lucius platform, was an Exxon-operated field with two large wells that were producing about 400 million a day of dry gas. We do not currently expect that production to come back online for 2018. That was about a $95 million reduction in our expected numbers, net to our interest. We own 60% of the Discovery system. While there are many other prospects in the area, we are actively bidding on large RFPs currently, but don't expect significant business to fill the gap this year. However, there are many prospects in the Keathley Canyon area for gas takeaway solutions that we expect to win.

That's very helpful. I'll pause there. Thank you.

Thank you.

Good morning. You've said before that after Atlantic Sunrise comes online, Chesapeake will be down to 10% of your EBITDA. I wanted to make sure that, that's about right? As a follow-up, would you be willing to comment on your next one or two largest customers? Are they E&Ps or utilities, and their approximate share of EBITDA?

Yes, your 10% number is fairly accurate as we move forward, though that’s dependent on asset sales that Chesapeake continues to execute. In terms of our largest customers, it's a mix. Cabot is now rising on the list with all the business we have in the Susquehanna Supply Hub and Atlantic Sunrise. Below that, you'll see a lot of big utility customers on the Transco system, with Southwestern emerging but not quite at Cabot's level yet.

Got it. That's really helpful. As a quick follow-up, a number of Marcellus E&Ps are discussing living within cash flow at least over the next couple of years. Has that impacted your growth outlook, or is it fair to think that the Northeast Marcellus is somewhat immune from that just because it's so takeaway-constrained?

We stay close to Cabot, who continues to generate cash, even in a low-price environment. They can operate in a low price and are capable of generating cash flows. Their movement into Bradford will benefit them as markets improve. In the Southwest Marcellus area, higher NGL prices spur cash flows for them. The consolidation we're seeing in the acreage is also driving growth. We’re better off as gatherers if growth comes in a steady pattern rather than spikes, leading to less capital investment per free cash flow for us.

Perfect. That answers my question. Thank you.

Thank you.

Good morning, everyone. I wanted to start off in the West. The volumes are good. Can you just remind us if the Haynesville contracts are higher margin than the other G&P areas in this section?

No, the rates are aligned with the market. We renegotiated those rates a few years ago and exchanged a lower rate for drilling obligations from Chesapeake. I would say our rates today are aligned with the market. The advantage is we had a lot of capacity built, which helps us maintain low operating costs.

I actually didn't mean relative to the market. I meant relative to the other areas in the West segment. So are the Haynesville rates higher than your Niobrara or Rockies?

No, they are not, but those systems are more mature. Our unit operating costs are pretty low for that area because the systems are already built out. Once they mature, we can keep pressure on our costs. So, on an operating margin percentage basis, it’s relatively good.

Okay. I wanted to go to your slide 8 in the presentation. The $425 million full-year contribution from Atlantic Sunrise and Garden State, I just wanted to clarify if these are gross or net numbers to you, as I think Atlantic Sunrise is consolidated in your financials, but the non-controlling interest line is below the adjusted EBITDA.

Yes, that is the gross number.

Okay. And do you have a net figure for that?

That is what goes into EBITDA, and then there will be a minority interest deduction number.

Lastly, WPX sold their San Juan acreage. What kind of impact do you expect to see from that, if any? Can you confirm that the contracts will transfer over to the new owners?

We haven't seen the contract shift yet, so it's too early to tell. We've always been able to work with our customers through credit issues in situations like this. We're continuing to see properties fall into the right hands, which is generally positive for us.

Great. I'll leave it at that. Thank you so much.

Thanks, Christine.

Thanks. On the Transco rate case, can you quantify the type of rate increase you're looking for? Are we talking double digits percentage-wise, or how much do you think you are under-earning on your current cost-of-service rates?

That will be determined when we conclude the test period/base period to form the rates, and I think that ends in May, which will form the basis for that rate in August. The numbers on Transco are large and it takes considerable direction to move those rates. Don't expect any major shifts.

Okay. That makes sense. As we think about the O&M increases you've had in the Atlantic-Gulf segment, should we consider what we're looking at in 2018 as a good run rate, or should we expect a step up or down as we look ahead to 2019? You've had your maintenance capital numbers stepped up decently well in the guidance versus the last couple of years. Can you discuss run rate operating costs, particularly around Transco?

Ted, first, you could conclude without seeing the details that our expansions are driving a lot of that cost; however, that’s not the case. The increased costs come from necessary pipeline integrity and maintenance programs. We’ve prioritized safety and proper maintenance, which reflects in our costs in 2017. That will continue as we go forth. But predicting what that cost is going to be is challenging because if you do see problems while hydro testing, you'd have to forecast the rate of repair required; when you indeed run the test, you won't know until then what repairs will be required.

Okay. That's great. Last one from me on CapEx guidance. $2.7 billion total, $1.7 billion at Transco. Can you bridge what goes into that $1 billion difference? Is it primarily the Northeast and some of the OVM spending you've talked about in Deepwater? A little more color on where that $1 billion comes from?

Sure. The Norphlet project we're doing for Shell in the Deepwater is included in capital. You'd see that being reimbursed even though we count that as capital. Some of that is reimbursed capital that shows up as capital spending, but gets reimbursed. The Northeast has a lot of growth, including the sixth expansion I discussed, as well as the build-out of Ohio in the Valley Midstream area. Out West, the Wamsutter area is the driver for growth as well. The Niobrara expansion will likely be more of a 2019 issue, specifically driven by existing growth opportunities.

Perfect. I’ll leave it at that. Thank you very much.

Thanks, Ted.

Hi. Good morning, guys. Maybe we can start off with balance sheet expectations and return of capital going forward. When you did the restructuring early last year, there seemed to be a goal to reduce leverage by about $5 billion. Having executed equity issuances and asset sales, where do you think we are until the agencies would view the consolidated entity as IG? What are your expectations for returning cash flow with respect to WMB moving close to paying off its revolver in the second half of this year?

On the return of cash flow analogy, there's a lot of considerations. The Tax Reform pushes out the date by which we would be a cash taxpayer at WMB. This is one of the benefits we had. The lower corporate tax rate we're paying is also factored. Once we're at a point where we evaluate our factors, we'll identify our best return decision.

As we exited 2017, WMB had about $270 million outstanding on its revolver generating approximately $100 million of excess cash flow every quarter after dividends. That will continue to pay down the revolver into the third or fourth quarter, further bringing our leverage down. While we expect leveled up slightly due to spending in 2018, once we see the full benefit of Atlantic Sunrise, it will drop again. For the consolidated debt levels to undergo investment grade improvements, we would need to be in the 4.5 to 4.75 times zip code of debt to EBITDA. It also depends on the timing the rating agencies give us credit for Atlantic Sunrise, but we can make a strong argument early in 2019.

Great. As a follow-up, in talking to E&P companies, how much do the IRRs for them to drill change as a result of projects coming online? Once that occurs, does that accelerate the opportunity for you to achieve what you outlined at the Investor Day of potentially investing $1 billion of capital in the Northeast at a 2.5 times EBITDA multiple?

We are aware of production from the Southwest supplying both power plants in the area and new markets. We can lead to more drilling activities as capacity is built up. We expect stronger growth from the producers prioritizing low-cost gas to maintain their cost structures, particularly the move by consolidating these plays effectively, which helps with long-term planning and commitments.

Final question regarding the Gulf of Mexico. It seems like producers are adding capital while drilling at lower-price oil levels. Do you see this as an emerging opportunity for Williams moving forward?

We are well-positioned in this emerging area, as evidenced by several large infrastructure development projects we are involved in. Shell's projects are evidence of this, coupled with an active of growth opportunities awaiting us with several large RFPs that we're responding to.

Great. Thank you very much. Really appreciate the color today.

Thanks, Shneur.

Morning. I wanted to follow up on the conversation about Northeast producers. Despite the pipeline capacity, it seems there are considerations that producers may pull off volumes from local hubs instead of adding new production over 2018 and maybe into 2019. What’s your view on that?

We formulate our forecast based on requests from our producers to increase their volumes. These requests come with obligations that stand behind their commitments. We have several options in the market growing to the south, and we are well-positioned to get gas to those growing markets.

Okay. Helpful. It looks like you're up about $250 million in the gathering piece. Can you frame the contributions beyond Haynesville? Were there significant contributors, or was it predominately Haynesville?

Haynesville was the biggest contributor; however, there were significant increases in the Niobrara on a percentage basis, and we also saw improvement in the Anadarko. Overall, we had strong improvements across the board.

Got it. Lastly, on maintenance, it seems relatively light versus the 2017 guidance. Is that tied to the O&M spend and moving some from maintenance CapEx to the operating expense line, or was maintenance just lower than expected?

The maintenance was indeed lower than expected across all franchises. We anticipated some work to shift from 2017 into 2018. We see several projects in process that didn't complete in 2017, shifting into this year, which is typical.

So with 2018 being flat versus the 2017 guide, does that imply 2018 would have actually been down, but some of that slipped?

No, I wouldn’t characterize it that way. We are seeing 2018 slightly ahead of 2017. We have a lot of work on the Transco system relating to both expense and maintenance CapEx; integrity and reliability projects.

To be clear, we expect an increase in maintenance capital from 2017 to 2018, and we came in below the $500 million guidance in 2017.

Thank you, guys.

Thanks.

Morning. I hope to drill down a bit on the excess coverage at WMB. Is it fair to say, if you have 1.36 excess coverage, your first priority after leverage pay-down would be projects that avoid public equity issuance? Is it basically just a matter of looking at WMB's net asset value versus its ownership of PZ? Should we assume that WMB buybacks move up the order of priority with that capital?

Yes, all valid points to consider. Tax reform also pushes out the cash tax payer date at WMB, which was beneficial, and lowered corporate tax rates are additionally helpful. As we note down the line, we'll pursue the highest value opportunities.

We exited 2017 with approximately $270 million on the revolver and aiming for a return to excess cash flow of around $100 million each quarter at WMB after dividends. We will pay down revolver into Q3 or Q4, lowering our leverage. Getting a solid IG rating will depend on being in the 4.5 to 4.75 times debt to EBITDA, depending on timing from rating agencies for the benefits from Atlantic Sunrise.

Shifting gears on Northeast, how do we see the multiyear outlook for Northeast G&P without Constitution and other projects? Do we significantly let down volumes until Atlantic Sunrise is fully online?

The outlook isn’t solely dependent on Constitution; we also have Diamond East on Leidy for capacity into Zone 6, which could contribute. The market growing to the south is positive for us and a source of gas supplies.

Thank you very much. Appreciate it.

Hey, guys. Just quick. Can you clarify the EBITDA building? I want to establish how much of it will be Transco line contributions and how much is just aggregate capacity utilization changes alleviating basis pressure in the Northeast?

The growth in EBITDA is largely driven from our fixed contracts and a good mix from our cost structure remaining flat combined with existing volume commitments. As for the volumes we expect at Transco, it's based on existing gathering contracts with producers. Those requests provide a robust outlook, contributing to our future volume predictions.

Thank you.

Thank you.

Hey, it's Cory filling in for Chris. Thanks for taking the time. Just two last quick questions. The first one is just about the Transco timeline. On slide 8, the $140 million walk from 2017 to 2018 assumes that the compressor comes online in July with months of delay for the greenfield pipe?

Yes. That's right. The contractors are anticipated to finish the pipeline segment by July, which involves commissioning with our teams. The compressor station completion will take a few months longer post this.

Okay. I'm assuming this was intentional, but can you separate Atlantic Sunrise and Garden State for us?

Sure. Please reach out to our IR team; we previously provided detailed numbers on that.

Lastly, just in terms of cadence for dividend and distribution growth in 2018, quarterly for PZ, annual for MB, was that a change?

Yes, we discussed the increase that we previously outlined. We’ll be making annual increases on WMB instead of quarterly distributions.

Understood. Thanks for your time, guys.

Thank you.

Thank you for your excellent questions. I appreciate your attendance today. We believe the fundamentals support the growth of our business. The low gas prices signify our confidence in the demand for expanding and getting low prices to market. Overall, we feel excited and well-positioned for growth as we target developments in LNG and gas-powered generation. Thank you for your time. I will now turn it over to the operator for any further questions.