Alpha Metallurgical Resources Inc (CTRA) — Q2 2018 Transcript

Thank you, Garry, and good morning to everyone. Thank you for joining us today for Cabot's second quarter 2018 earnings call. I am accompanied today by members of Cabot's executive team. I want to highlight that during this call, we will make forward-looking statements based on our current expectations. Some of our comments may include non-GAAP financial measures. Details on forward-looking statements, other disclaimers, and reconciliations of the most relevant GAAP financial measures can be found in this morning's earnings release. For the second quarter of 2018, Cabot reported adjusted net income of $57.9 million or $0.13 per share, down from $0.14 per share in the same quarter last year. Our adjusted net income for this quarter was affected by a $51.1 million exploration dry hole expense due to our decision to stop investment in one of our two exploratory operating areas. If we exclude this one-time charge, our adjusted earnings per share for the quarter would have been about $0.09 higher. Daily equivalent production for the quarter averaged 1.895 Bcfe per day, landing at the high end of our guidance and reflecting a 4% sequential increase compared to the first quarter, after adjusting for the Eagle Ford Shale, which closed at the end of February. We also saw improvements in our unit costs, achieving an 8% decrease compared to the same quarter last year. After excluding the previously mentioned exploratory dry hole expense and a one-time non-cash interest expense related to tax reserves, our unit costs would have improved by 24% over the previous year and by 4% sequentially from the first quarter of 2018. Despite strong production volumes and better cash operating costs, the Company experienced a free cash flow deficit in the second quarter, primarily due to lower than expected realized prices in May and June, along with funding most of the remaining capital for our equity investment in the Atlantic Sunrise pipeline project. We expect to return to positive free cash generation in the third quarter due to anticipated better price realizations and increased volumes. In pricing terms, May and June bid week prices were approximately 18% lower than in April, which affected our realized prices for the quarter. However, we have seen improvements in Northeast Pennsylvania pricing, with July bid week prices settling 15% higher than the average for the second quarter and early signs suggesting that August prices will be similar to July. The forward curve indicates that our third quarter price differentials would be 10% to 15% better than in the second quarter. Regarding our share repurchase program in the second quarter of 2018, Cabot repurchased an additional 11.6 million shares at an average price of $23.54, bringing the total year-to-date to 20 million shares. Including dividends paid this year, we have returned about $535 million in capital, representing a total shareholder yield of 5%. At our board meeting yesterday, we received approval to increase our authorization by another 20 million shares, effectively reloading the program to 30 million shares or roughly 7% of our current outstanding shares. With a strong balance sheet and an expectation of ongoing free cash flow expansion, we remain committed to executing our share repurchase program opportunistically as long as there’s a disparity between our share price and our assessment of the Company’s intrinsic value. Since reactivating the share repurchase program in the second quarter of 2017, we have decreased our shares outstanding by 5% to 441 million shares and if we fully execute the current 30 million authorization, we will bring our shares outstanding down to levels below those before our equity issues in early 2016. On the exploration side, we recorded an exploratory dry hole expense during the second quarter related to one of our exploratory operating areas. Based on the data collected over the past year, we decided to stop capital allocation to this area. Last year, we announced a limited capital allocation for exploration, making it clear that our main focus was on generating returns from the Marcellus shale and returning more capital to shareholders through dividends and share buybacks. We acknowledged the value in allocating a small part of our budget to exploring new concepts that could yield long-term benefits. However, we maintain a high threshold for internal capital allocation based on the returns from our premier assets in the Marcellus. If any new venture couldn’t deliver competitive full-cycle returns, meaningful inventory depth, resource longevity, and self-funding capabilities in a low commodity environment, we wouldn't hesitate to move on, which is our current position regarding this exploratory area. We will continue to evaluate our second exploratory area and plan to provide an update during the third quarter earnings call in October. Our financial standing is strong with over $2.4 billion in liquidity and a net debt to trailing 12-month EBITDAX ratio of 0.8 at the end of the quarter. After the quarter ended, we completed our announced divestiture of Haynesville for about $30 million and paid off our $230 million senior note that matured this month, using cash from our balance sheet. While this transaction did not affect our net debt to EBITDAX, it reduced our absolute debt to EBITDAX from 1.5 times to 1.3 times, comfortably within our target range of 1 to 1.5 times. We anticipate continued deleveraging over time as our cash flows increase in the upcoming quarters due to rising production volumes and improving price differentials, resulting in additional balance sheet capacity for future capital deployment. Operationally, we had a strong performance in the Marcellus in the second quarter, with volumes up 4% sequentially despite significant planned and unplanned downtimes. Our production guidance for the third quarter of 2.1 to 2.2 Bcf per day reflects an 11% to 16% sequential increase compared to the second quarter, driven by the expectation of bringing 37 wells into production. However, due to actual year-to-date volumes being slightly below our budget, mainly due to delays in third-party compressor stations and downtime on Transco and Millennium, we have revised our top-end annual production guidance from 10% to 15% down to 10% to 12%. Additionally, we are guiding more conservatively for the second half of the year, given the rapid ramp in production at a time when we typically experience high line pressure and pipeline maintenance issues. Therefore, we are prioritizing caution. Regarding asset productivity, we continue to complete additional wells in the Upper Marcellus and are closely monitoring data related to our enhanced Generation 5 well completions. Previously, we noted that we have 30 Upper Marcellus wells completed with older designs that are currently performing according to our 2.9 Bcf per thousand lateral feet type curve. Our ongoing efforts support the promising potential of the Upper Marcellus reservoir distinct from the lower Marcellus. We have strong confidence that both zones' productivity will yield excellent economics compared to most other oil and gas resource plays in the U.S. As mentioned last quarter, we are making significant progress on various infrastructure and in-basin demand projects. To recap briefly, the Dominion Cove Point LNG facility was commissioned on April 9th, and our 20-year supply agreement with Pacific Summit Energy is now active. We are meeting that obligation through a mix of purchases and equity production. As you may know, William announced last week that the Atlantic Sunrise project is nearing completion, with expectations for service in the latter half of August, weather permitting. This greenfield pipeline will serve as Cabot's exclusive transportation route to fulfill 100% of our LNG commitment, linking directly to our equity production in Susquehanna County. We are eager to supply around 350 million per day to Cove Point via Atlantic Sunrise soon. Additionally, I want to remind everyone about Cabot's 15-year agreement with Washington Gas Light for approximately 500 million cubic feet per day, alongside several other sales agreements that will take effect with Atlantic Sunrise's commissioning. In conclusion, this long-awaited pipeline infrastructure will enable Cabot to deliver about 1 Bcf per day of production to new markets with significantly improved price realizations. Transitioning to our in-basin power projects, the Lackawanna Energy Center was brought online on June 1st, with train 1 operating consistently at around 70 million cubic feet per day. Trains 2 and 3 are on track to commence service on October 1st and December 1st, respectively, with train 2 currently undergoing testing. Regarding the Moxie Freedom power generation facility, we previously reported an early in-service possibility of June 1, but further modifications and testing were required. However, we recently received updates that full service for the Freedom plant may be as early as the first week of August, with substantial test gas currently being provided as we await final approval for this 160 million day project. These three projects will significantly enhance our differentials in the future, thanks to access to premium markets after Atlantic Sunrise commences service and exposure to higher seasonal power prices. These are indeed exciting times for Cabot as our long-term infrastructure and growth strategies are finally aligning, which will provide tremendous advantages for years to come. In summary, we firmly believe that our distinctive approach to high-return growth, alongside increasing returns on capital and distribution of capital, is not fully valued by the market due to general indifference towards natural gas as an asset class. However, if you were to consider natural gas as an alternative commodity with similar financial returns and leverage metrics, our performance, reflected in year-to-date share price movements, would likely appear much more favorable. That said, I have been in this industry long enough to understand that market sentiment around commodities will evolve. I am particularly confident that this will occur soon for natural gas, both due to the current storage deficit—the lowest since 2014—and the approaching critical demand shifts for natural gas from exports. Regardless of how the market feels about the commodity, I assure you that the team at Cabot will remain committed to this strategy to create long-term value for our shareholders. Gerry, I would be glad to answer any questions.

Dan, in your prepared remarks, you talked about the Upper Marcellus test that you drilled in the past. Can you just talk about what assumptions you made in that forecast for the Upper Marcellus?

The 20-year forecast that you’re talking about we’ve assumed where we’re today and what we’ve seen, Drew, with the 30 completions that have been completed with our old techniques. We’ve assumed the 2.9 in that forecast.

And then, on the focus on returning cash to shareholders, can you just update us on thoughts on dividends?

Yes, on the dividends every board meeting, we have discussions on dividends. We made it clear when we started ramping the dividend and we took kind of incremental steps last year. Our commentary at that time was that it was our intent and the board’s intent to see the commissioning of these infrastructure projects that are imminent to commission. And we felt it was prudent at the time to make sure that there were no delays. We’ve all experienced the pains of delays with some of these projects and getting them commissioned. So we thought it was prudent to keep the dividend where it is right now. Once we get the cash flow coming in the door from the commission of these infrastructure projects, we would then again revisit the dividend policy.

Thanks a lot, Dan. Just one last one from me. When you started this exploration play process, you said if you didn't have success then you would market the acreage on the backend. Is that still the plan?

We've taken the write-down on some of the capital expenditures that we spent, and the acreage is still intact, and we will go through that process on the back end.

Hey guys just a question around CapEx here. Can you provide some color on where we should see kind of CapEx over the next couple quarters?

Well, our guidance on CapEx for the full year will remain intact. As we bring on wells into the infrastructure, we'll continue to complete those wells and bring those wells inline. So, we have a little bit of a ramp up heading into the commissioning of Atlantic Sunrise.

Okay, and I guess just looking at the share repurchases, should we expect you guys to still plan on being pretty aggressive here in the second half of the year with the buyback program?

Yes, Leo. The conversation again at our board meeting this week was specifically along the lines that I have mentioned in the past that our authorization is not optics; it is proaction. It is our intent to execute on the authorization that the board has granted. So the takeaway would be that we fully intend to continue our program that we have implemented.

Okay, that's helpful. And I guess just lastly on the Upper Marcellus wells that you mentioned, do you have any early indications out of those?

Well, the early indications are wrapped up in my comment that we continue to believe that our Upper Marcellus is an incremental and accretive reservoir independent of the lower. We work as indicated that and we're also of the opinion that our completion techniques will improve off of the 2.9 per thousand foot lateral.

Can you give us a sense of what we should be looking for going into 2019 on the completion pace?

The increased second half of 2018 has always been in our design, as we get to the commissioning of Atlantic Sunrise. So that level of activity and timing of this activity is right on cue. In regard to '19, we don’t anticipate bringing in any additional frac crews than what we have done in 2018. We're staying fairly consistent with our completions in '19, and some of that is dependent upon the timing based on how many wells we have on any given pad and how many stages in the lateral lengths on those pads.

I wanted to ask you a couple of questions about guidance being conservative in the back half of the year. Could you provide more detail?

Are you missing the conservative part? I wouldn't try to be cute on the comment on conservatism, Charles, but one of the things that I think is relevant, the ramp-up and shifting in a small area of 1 Bcf of gas and coordinating two power units that are coming on at the same time and moving gas around in a small geographic area is done with a — it's multiple valves; it’s multiple coordination to get it done and get it all smoothed out. So, in light of the time of the year, when you get a little bit of the early cool weather, it ramps up the pressure in the pipes. The amount in volumes that the pipelines will accept at a higher pressure starts creating some reduction in the volumes you'll be able to put into the pipe. That has happened every year back-to-back without exception.

Does that imply that you see less variance from quarter-to-quarter than we had in 2018?

That's getting fairly detailed, Jeffrey. I will need to follow up with you on that, but my initial thought is that I expect the guidance to remain fairly stable throughout the year.

One thing I'd add is, we have to be careful about looking at quarterly turning lines because if we have an 8-well pad that's completed in the last week or two of the quarter and it gets pushed into the next quarter, that would drastically change the outcome.

Can you give us some color on whether potentially it's economic even though it didn't meet your hurdle?

No, we did find hydrocarbons and there's some dynamics going on, as we are all aware of in the Permian. In the last couple of years working on this project, you are seeing near-term headwinds on infrastructure out there. You have seen service costs increase out there in the last couple of years. And even though you have seen certainly an increase in the commodity price there's still some punitive differentials today and going to be apparent for a little bit longer until we get the pipeline built out there. The results that we have gotten in the field did not have competitive returns based on the other impacts affecting our return. As a result, we made the decision not to move forward.

How do you see asset maintaining a balance sheet improved among some of the players bearing in mind the competitive dynamics?

I think that when looking at Appalachia and considering natural gas, some parties have the ability to increase production profiles, complete ducks to move gas to a different price points. This approach could yield better realizations, which I think is prudent. Overall, every company has its own strategic initiatives and internal complexities, but I think that conversations among management will focus on how to become more capital efficient to allow growth without compromising production realization.

Just curious if we should expect any optimization at all on the LOE side?

From our number that we're seeing in '18, I think it is safe to say looking at '19 that we would expect a tick down in our direct costs associated per unit.

Could you please update us on the East project and what do we need to pay attention to from a regulatory standpoint?

PennEast has not changed their disclosure for the second half of 2019. They made significant progress on permitting in Pennsylvania but still have challenges in New Jersey. I understand the PennEast owners, being public companies, have analyst calls coming up in a few weeks, and we will monitor that to see if they push that back.

Thank you, Gerry, and I thank everybody for the questions and interest in the details. We are looking forward to our October quarterly call. That call will be the first call in many years that hopefully we’ll have the privilege of discussing the commissioning of many overdue infrastructures and I would look for the opportunity for us to again support the shareholder-friendly decisions we have made in the past, along with the clarity of cash flow that we’ll continue to make in the future. So, thank you, and I look forward to the third quarter conference call.