Cabot Oil & Gas announces $62.1 million in cash flow from operations

Cabot Oil & Gas equivalent production in the first quarter of 2016 was 160.3 Bcfe, consisting of 153.1 Bcf of natural gas, 1.1 MMBO of crude oil and condensate, and 92 MBO of natural gas liquids (NGLs).

Cash flow from operations in the first quarter of 2016 was $62.1 million, compared to $267.4 million in the first quarter of 2015. Discretionary cash flow in the first quarter of 2016 was $71.2 million, compared to $240.2 million in the first quarter of 2015. Net loss in the first quarter of 2016 was $51.2 million, or $0.12 per share, compared to net income of $40.3 million, or $0.10 per share, in the first quarter of 2015. Excluding the effect of selected items, net loss in the first quarter of 2016 was $55.4 million, or $0.13 per share, compared to net income of $49.2 million, or $0.12 per share, in the first quarter of 2015. EBITDAX in the first quarter of 2016 was $100.9 million, compared to $279.4 million in the first quarter of 2015.

Natural gas price realizations were $1.49 per Mcf in the first quarter of 2016, down 39% compared to the first quarter of 2015. Natural gas price realizations for the quarter implied a $0.60 discount to NYMEX settlement prices compared to a $0.75 discount to NYMEX settlement prices in the first quarter of 2015 (excluding the impact of hedges). Oil price realizations were $27.65 per barrel, down 37% compared to the first quarter of 2015. NGL price realizations were $7.22 per barrel, down 35% compared to the first quarter of 2015.

Operating expenses (including financing) decreased to $2.26 per Mcfe in the first quarter of 2016, a 3% improvement compared to $2.33 per Mcfe in the first quarter of 2015. Cash operating expenses (excluding depreciation, depletion and amortization; stock-based compensation; exploratory dry hole cost; and amortization of debt issuance costs) decreased to $1.18 per Mcfe in the first quarter of 2016, a 6% improvement compared to $1.26 per Mcfe in the first quarter of 2015.

Cabot drilled 10 net wells and completed 21 net wells during the first quarter of 2016, incurring a total of $91.7 million in capital expenditures associated with activity during this period.

Natural gas production in the Marcellus up 10%, oil production from the Eagle Ford down 13%

During the first quarter of 2016, Cabot averaged 1,628 MMcf/d of net Marcellus production (1,913 gross operated Mmcf/d), an increase of 10% sequentially compared to the fourth quarter of 2015. During the first quarter, COG drilled 7 net wells, completed 12 net wells and placed 8 net wells on production.

Cabot is currently operating 1 rig in the Marcellus Shale and plans to remain at this level for the remainder of the year.

The company’s net production in the Eagle Ford Shale during the first quarter of 2016 was 12.98 MBOEPD, a decrease of 13% sequentially compared to the fourth quarter of 2015. Net oil production during the quarter was 11.9 MBOPD, a decrease of 6% sequentially compared to the fourth quarter of 2015. In addition to natural production declines resulting from reduced operating activity, the primary driver of the lower sequential equivalent production was unscheduled downtime at a third-party processing plant which impacted natural gas and NGL volumes for a significant portion of the quarter.

During the first quarter, the company drilled 3 net wells and completed and placed on production 9 net wells, the majority of which were placed on production late in the quarter.

Cabot is not currently operating a rig in the Eagle Ford Shale and plans to drill 3 additional wells in 2016, all of which are scheduled for the second half of the year.

Debt levels cut substantially in the first quarter

During the first quarter of 2016, Cabot closed on an offering of 50.6 million shares of its common stock (including the over-allotment option) for net proceeds of $995.6 million. The company used a portion of the net proceeds to repay borrowings outstanding under its revolving credit facility.

As of March 31, 2016, COG had total debt of $1.6 billion and cash on hand of $579.3 million. The company’s net debt to adjusted capitalization ratio and net debt to trailing twelve months EBITDAX ratio were 25.8% and 1.6x, respectively, compared to 50.1% and 2.5x as of December 31, 2015.

Effective April 19, 2016, Cabot’s borrowing base was unanimously approved by its 20 lenders at $3.2 billion. With $1.6 billion of senior notes outstanding, this leaves the COG with approximately $1.6 billion of available commitments under the $1.8 billion credit facility. The Company currently has no debt outstanding under the credit facility, resulting in approximately $2.2 billion of liquidity. Cabot’s next annual borrowing base redetermination is scheduled for April 2017.


COG conference call Q&A

Question: With regards to Northeast PA, what sort of rig activity do you think we would have to see up in that area to stem declines? Also, are there other opportunities outside of East Texas for portfolio clean-up? Why don’t you think we’ve seen more consolidation among the gas names in the current environment?

COG: First in the Northeast PA, our study, I’ve given you some of the details of our study. We have an ongoing evaluation and plan on keeping this as a dynamic project to evaluate the production profile. And the coincidence between drilling and completions will dictate the level of activity necessary to show that production and maintain production at the level it is today. Certainly, we feel that three rigs and the number of frac crews up there is not the level of activity that we’ll maintain. We anticipate a fairly meaningful decline in production. In regard to the East Texas sale, we do have some additional properties in East Texas that we maintain. This was not all of our East Texas assets. And we do not have those on the market at this period of time, but certainly have additional assets that not only in East Texas but along the Gulf Coast that would be part of our portfolio.

The consolidation amongst the gas players, I think, is a result of the commodity price sitting at the first quarter, or at historic – not historic lows, but lows as I mentioned in my opening comments all the way back to the first quarter of 1999. Consolidation in a very, very, very low market like that is difficult at best with some parties as we’ve seen having stresses in different components of their business, balance sheet, or possibly not having a portfolio that would look good in a slow commodity price environment. So consolidation in this environment makes it difficult. I would think that if you have continued support in the commodity price and you can see a more normal vision out there on the strip, then you might see a little bit more activity.

Question: You gave us a lot of detail on your Northeast supply, but maybe you could share a little bit more on the conclusions or what it suggests to you. And specifically you guys guided to a tighter natural gas realization in Q2, but do you see that continuing into the back half of 2016? I think I picked up on that from your comments. And does that even tighten enough that it raises questions about the economics of new take away out of there if bases got that tight?

COG: Well, I think on the supply side my reference to 25% or even 30% depending on looking at our models decline that’s occurring is it’s a real number on the baseline decline. And the level of activity with three rigs and less than a handful of pumping units up there I think it is apparent and I think we are seeing a meaningful decline, and I think that’s being reflected in the differentials that you’re referring to, and that our guidance is based on our expectations, our supply study we’ve done up there. Our expectations are that the supply side will continue to diminish, that you’ll have narrowing differentials, and I think that will certainly bode well for realizations.

NYMEX is going to do what it does, but certainly the northeast has been one of the most punitive areas for differentials. And I think now that – with the supply side and lack of activity, it is now coming in, in more parity with other areas of the country. I would expect that when you look at the parties that are up in the northeast that have positions, I don’t think the Northeast PA is going to be an area that they’re going to run up to and commence a program any time near term. So I do expect to see continued narrowing of the differentials, and I think it’s a positive for Cabot.

Question: On Constitution, I need to respect the boundaries you put about what you want to talk about and what you don’t, but if I could just kind of explore a little bit where those boundaries are, it seems like you are regarding this as a delay, a delay, but that, in your mind, or in Cabot’s posture, this project is still going to get done. Is that the right read that we should take from your comments?

COG: Yes, it’s exactly right. We have looked at New York’s own projections. Their 2030 projections have Constitution or additional gas as a part of their energy source. They anticipate that in 2030, that natural gas is going to represent about 50% of New York’s fuel source, and the natural gas has to get up there and meet that demand in some way. The fact that the Constitution Pipeline and others are fully subscribed projects represent the demand that’s necessary up there, and it’s for the public need. And so when you look at what the future holds, the grants that New York has given to some of the southern tier counties in New York for taps into Constitution Pipeline for the use of natural gas in areas that are stranded and do not have the use of natural gas, I think it is obvious that the public need and the majority would benefit from Constitution being a fuel source for energy in New York.

When you look out ahead and you look at a desire to have renewables, we all know that we are a company and an industry that endorses renewables as part of the energy mix. We’ll continue to endorse renewables as part of the energy mix. But we also think it’s prudent to be realistic about scalability, timing, and to take in consideration the costs associated with renewables in this environment, and the general public and the consumer, and what it will cost if, in fact, there’s not access to natural gas as the clean fuel that it is.

Keep in mind that a lot of the benefits from the CO2 reductions that we see today are a direct result of natural gas being a fuel source, and it’s not a hard equation to – and it’s not a difficult set of facts to understand. Though they, at times, are not represented in a lot of the media print.

Question: If you think about your portfolio, are you currently happy with your portfolio? Does it need any additional changes?

COG: Well, we love the assets. I think it’s well documented that the footprint of our Marcellus assets, though challenged on getting infrastructures to this specific area, as illustrated by Constitution, we still think the future is going to allow some of the best assets in North America as far as natural gas is concerned to yield great dividends for Cabot shareholders. Would we like to have assets that would be out of a footprint that is narrow scoped like where we are in Northeast PA and not have the infrastructure overhang that we discuss every quarter and every conference we go to? That would be nice, and I would enjoy that. But I’m not going to compromise or dilute the best assets in North America.

Question: On the two additional projects you mentioned were in the works, how long term are these? Meaning when is the earliest they could contribute to incremental demand for Cabot Gas? And can you talk about what indices these would be tied to or whether it could be fixed pricing?

COG: Really wish this call was a few weeks away so we could talk in detail about these two projects. One has to do with bridge capacity. That capacity that can start as early as next spring. And the duration of that is up in the air at this point. We can make it three years or out five years to 10 years. The second project has to do with – it’s a demand project with an end user. It’s a large scale and it’s in the 10-year to 15-year timeframe. And it would start, also, probably late 2018.

Question: How much ability does Cabot have to sell more gas into the local market at the right price if local gas prices were to, say, rise to $2.00 an Mcf in 2017 level where returns to Cabot are very strong? Are you able to increase volumes at the expense of price or are you physically just unable to sell more gas than you’re already producing above that feed?

COG: When you look at the study that we’re doing up there, and you take in consideration the supply side diminishing somewhat for Cabot to be able to pick up incremental space in the pipes, I think [we’re] very confident that we would be able to do that. There’s also been conversation about firm capacity that with the low commodity price, the stressed balance sheets and capacity commitments that have been committed to, that there would be opportunities in different areas to maybe move additional gas.

Question: The NYMEX future strip agrees with you as gas for 2017’s roughly $3.00, so what does Cabot look like at $3.00? You’re on a run rig right now in Northeast PA. How many could you run? And then, if you push the growth accelerator in a higher price environment, how long does it take you to get a response given the evisceration with what’s happened on the service side as far as people, specifically?

COG: Well, on the response side first, the maintenance capital and capital intensity of what’s necessary to propel acceleration in Cabot’s production profile is quite low. It does not take a lot of rigs and does not take many frac crews to be able to ramp our production with the quality of rock that we have.

In 2017, as an example, it would only be a – throw out a number, $250 million or so – to just kind of keep our production flat at $3.00; and if we wanted to just do that, at $3.00 we would be generating a significant level of free cash flow. And the ramp-up or taking advantage of the opportunity at higher price, it’s part of our planning process right now and we’re looking at the strip price. We’re planning on the infrastructures projects that we referred to, and we will be building a program that allows us to ramp up production, not only in 2017, but I would say on our first pass, second pass sensitivities on 2018 – quite significantly in 2018.

Question: I know this is a hard question to answer, but just curious if you could provide what curtailments are right now for Cabot in Northeast PA.

COG: Now, I’m not going to get into specifics of exactly what it is, but consistent with what we did this last year, we have a measured amount of curtailments in our volumes. And when you look at the December or so rate of 8.4 Bcf per day and rolling forward now to the 7.6 Bcf per day, there might be some curtailed volumes in that number, but I think it’s safe to say that everybody is working off – by the lack of activity, everybody is working off their level of curtailed volumes and getting close to a baseline production.

Question: You all continue to make improvements on the efficiency side in the Marcellus. Could you maybe provide some color there in terms of the drivers? Then, on the other side in terms of productivity, is there anything you’re testing that can drive that higher?

COG: In both areas, what we’re working to do is stretch out the length of our lateral. As we put in the quarterly results, we drilled or completed about a 1,000 foot longer lateral, and that doesn’t really – in terms of the drilling costs, that’s a very efficient portion of the operations. We can drill another 1,000 feet in a very, very short period of time, and that equally just offsets the amount of extra casing. So that’s a very, very efficient portion of the operation.

We are still seeing a little bit of softening in some of the service prices, so we’ve been able to take advantage of that. In the south we again have been working to complete the longest possible laterals we can and using technology like dissolvable frac plugs and so forth – all of that to reduce the mill out time or the amount of time with coiled tubing rigs that we have on location to drive our average costs down. So those are some of the things that we’re working on.

On the LOE side, we’re really looking hard at what our water disposal costs are, and in both areas, we work very hard to drop those numbers throughout the year and especially quarter over quarter. And same thing on the chemical side, in the Northeast we’ve reduced some methanol use as we had a milder winter, and in the south again working on our chemical efficiencies.

The other thing I was going to mention is in the south, we also are putting in quite a bit of electric infrastructure, quite – right now we’ve got over 50% of our wells on either utility power or on microgrid, which is significant cost savings from generation.

Question: Got it. And then I’ll try one on the infrastructure side. So I mean generally, northeast, we’ve seen varying degrees of localizability with the new pipeline projects, and that’s obviously impacting the timing or status of proposed projects. And then you balance that at the federal level, where FERC has been moving forward with projects that are in the interest of the public. So my question is do you see strategic importance in having the course clarify what the role of the state is in the pipeline regulatory process?

COG: Well, just from kind of a macro comment, I think with the ramp-up in the activists that are against hydrocarbons, and their attack has now – narrowing down to infrastructure, and I think there is the sense that if we stop infrastructure, or we fulfill our “leave it in the ground,” comment. I think from both a state and federal perspective, I think it is prudent to evaluate the process, look at where the impedance are coming from, look at, again, the overall value of a fuel source, and determine what process is prudent to move forward to represent the majority, that at times might not have a voice. So I do think that we are in an area that would – is important that we do get clarity and we do understand the roles that are necessary to facilitate the greater public need versus a more specific agenda.

Question: I just wanted to expand on a few of the other questions you have been asked today. First, starting with the commentary around your internal team looked at, I guess, 25% year-over-year decline in Northeast Pennsylvania, absent, I guess, a working down of backlog and perhaps some curtailments. But if you couple that with your comments about others in your area not necessarily using their capacity, have you already started conversations with your neighbors about perhaps picking up some capacity in 2017 that you could trade them for perhaps longer down the road or pick up now that they don’t intend on using? And if so, how receptive are those conversations right now?

COG: We started these conversations probably six months to nine months ago, not only with our neighbors in Northeast PA, but really in the entire Marcellus Utica Basin. It even gets a little further than that, as some of the legacy contracts are also not being used. In other words capacity from the Gulf Coast. It even gets deeper when you start looking at the future commitments on projects and the unused capacity that could be available there as well.

So we’ve been slow dancing this a little bit only because we think that the timing is getting better. Each month that passes, we’re seeing better opportunities. And so we’re going to step into a little bit of additional capacity here, and maybe not for the duration that some of that you’ll read about in the new projects. But there’s definitely an improvement in the secondary capacity market. And I just think it keeps getting better.

Question: My next question just on the balance sheet and free cash, your updated CapEx today, I think, obviously makes sense not having the pipeline commitments, and looks like you’d be generating free cash this year and conceptually free cash in 2017. For now, does the free cash just get used for balance sheet purposes before you have better visibility on take away projects? And I guess sort of dovetailing on the question earlier about the portfolio, with excess free cash, do you start looking up at beefing up other areas outside of the Marcellus that are in your portfolio?

COG: In response to your first question, the answer is yes. We would just use it for just to kind of, for lack of a better word, weather the storm and see just the ebb and flow. We are modeling it similar to that, with the free cash flow this year and next year. At least in several of the plans that Dan referenced in his prepared remarks. But you’re spot on. As Dan answered that question, we are looking at our portfolio. And looking at, we still believe from a RoC perspective, we got the best RoC on the natural gas side of the equation in what we have in the Marcellus. And if we can beef up a position with high quality assets, we would be willing to use that free cash flow and some of the cash we have on the balance sheet to explore those ideas, too.

Question: Regarding the East Texas assets that were sold, was that legacy Haynesville or was that something else? And was there any acreage associated with the sale, like a very good price given the amount of reserves contained, and was there any production, too?

COG: Yeah, the production was kind of in the mid teens, and it was more the Cotton Valley assets and not the Haynesville.

Question: And the third party shut-ins in the Eagle Ford, how much did that impact the quarter? And is there any impact into second quarter, or has that all been resolved?

COG: That was about three quarters of a Bcf, just those alone for us in the south region. It was down most of – or half or so of the first quarter, and it’s back online about April 20 or so.

Question: You mentioned on the transportation side you were working on or were close to signing some new projects, some of which are demand driven. Certainly, not surprising that the demand is there, but what gives you confidence that they won’t face some of the similar issues that we’re seeing, or is it just because those projects take gas to a different direction, different point?

COG: I think it’s – I agree with some of what I read out there right now that the midstream space is being challenged by an effort to basically keep hydrocarbons in the ground, point-blank. I do agree with it being more difficult, and the activists trying to stop progress on the midstream. I think in certain areas of the country, it will be more pronounced than others, and geographically it seems to be up in the east right now where it’s a little bit more populated; it seems to have more intensity and more emotion attached to it. But, again, I’ll go back to what we referred to last quarter, and you look at the footprint necessary to get a certain level of energy to a demand source.

Natural gas has one of the smallest footprints that there are out there. If you make an equivalence to renewables and what it takes to deliver equivalent production, what’s being discounted and not discussed is the footprint necessary to be able to deliver renewables and the equivalent production level. So all those things are part of it, but I think geographically it’s going to be more difficult in other areas to lay the infrastructure. But I do think that the process is being considered by the administrators in a way differently than it has been in the past. And I think it’s clear that there’s not scalable opportunities for renewables to take the place of what hydrocarbons, and natural gas in particular, will deliver as far as demand is concerned; so just a difficult time right now.

I do feel, though, that with the projects that we have in place, I think the mitigation discussions that we’ll have going forward to mitigate in an objective way will also come into play. I think we do that, but we’re going to be better at that aspect of it. We’re certainly sensitive to all the needs out there, and we’ll continue to move forward with what we think are projects for the majority’s need.

Question: And kind of tying that back into some of the efficiency questions on the upstream side that you answered questions on earlier, I think you made a reference to some chemical type efficiencies. I just wondered whether, given some of the concerns out there, rightly or wrongly, with regards to water and chemicals in the water, et cetera, do you see – have tested or are testing any technologies that would significantly improve what some would call green footprint in terms of reductions in chemical intensity? And do you think that that has a place in the Marcellus?

COG: Well, first off, let’s back up to the premise that is the reason for the question. One is what is the level of contamination of any water in the first place? That question has been evaluated in a lot of different ways, water well tests, and it’s a significant amount of dollars and significant database that represents to us that the water has not been contaminated by the operations.

On the chemical side, drilling side, we have a closed loop system. We have, also, through the frac side – we have a closed loop system on the frac side that lets us accept what we put into the formation.

So we’re confident that our operation using best available technology is mitigating any concern about water. Do I think that there are other areas that maybe has volumes of produced water, and those volumes of produced water then going through a process different than today and continuing to look at produced water and how you dispose of produced water? I think there’s probably ongoing research that will continue to look at that and try to improve in an area that’s very good right now, but would try to improve on any produced water disposals.

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