Coterra Energy Inc (CTRA) 2016 Q1 法說會逐字稿

Good day, and welcome to the Cabot Oil & Gas Corporation first-quarter 2016 earnings conference call and webcast.

(Operator Instructions)

Please note, this event is being recorded. I would now like to turn the conference over to Mr. Dan Dinges, Chairman, CEO, President. Please go ahead, sir.

Thank you, Rocco, and good morning, and thank you for joining us today for Cabot's first-quarter 2016 earnings call. With me today, are the members of Cabot's executive management team.

And before we get started -- excuse me -- let me say that the standard boilerplate regarding forward-looking statements, including in this morning's press release, do apply to my comments today.

As an opening comment, I think it's impressive that during the worst quarter our industry has faced in many years, Cabot's first quarter results highlight our ability to deliver growth, without burdening the balance sheet even in this low commodity price environment.

Cabot grew daily equivalent production by 7% sequentially, compared to the fourth quarter of 2015, while funding all investing activities with a combination of operating cash flow, and proceeds from a non-core asset sale. At today's strip prices, we do anticipate that the Company will be able to deliver a cash flow neutral to cash flow positive program each quarter this year, as price realizations continue to improve, and capital spending continues to trend downward over the next few quarters.

Despite a significant improvement in our natural gas differentials during the quarter, which improved from a minus $0.75 in the fourth quarter of 2015, to a minus $0.60 during the first quarter of 2016, the Company experienced its lowest price realizations in many years. The lower realizations were the result of an average NYMEX settlement price of $2.09 per MMBtu during the first quarter, which was the lowest average NYMEX price we have witnessed since the first quarter of 1999. While lower prices have certainly had an impact on industry-wide margins and cash flows, including Cabot's, the good news is that the outlook for natural gas prices continues to improve, as the country is beginning to experience a decline in dry gas production, stemming from a significant reduction in drilling and completion activities, and an improvement in natural gas price, excuse me, natural gas demand driven by increased power generation and exports.

While the improvement -- the differentials had a meaningful impact on our results for the quarter, our ability to continue to lower our cost structure has also held the bottom line. Cash costs including G&A and interest expense during the quarter were $1.18 per Mcfe, compared to a $1.26 per Mcfe during the fourth quarter of 2015. In addition to our reduction in unit costs, we also reduced our capital spending relative to the fourth quarter of 2015, highlighting our commitment to financial discipline.

As mentioned, and as you are all aware, one of our core tenets is our commitment to maintaining our balance sheet strength. We took a major step during the quarter to ensure that strength, by issuing approximately $1 billion of equity in late February, with a portion of the proceeds used to pay off the outstanding borrowing on our revolving credit facility. Subsequent to the offering, the Company is extremely well-positioned to weather the current environment and remain opportunistic, with liquidity of approximately $2.2 billion, and a net debt to EBITDAX ratio of only 1.6 times at quarter end. Additionally, subsequent to the quarter end, Cabot's bank group unanimously approved a borrowing base of $3.2 billion.

Moving into the region, in the Marcellus, we continue to operate one drilling rig and one frac crew working daylight hours only. During the quarter, we drilled 7 wells and completed 12 wells. Our primary focus is on enhancing operating efficiencies, resulting in further cost reductions. The success of these efforts was evident in the first quarter, with drilling and completion cost savings of approximately 14%, compared to the fourth quarter of 2015.

On average, usable lateral length for the seven wells drilled during the first quarter of 2016 was over 7,400 feet, which exceeded our previous best quarter average by over 1,000 feet. Even with the longer laterals, we were able to maintain average drilling days flat, relative to the fourth quarter of 2015 at 12 days from spud to TD. On the production front, we averaged over 1.6 Bcf per day in net production for the quarter, while reducing direct field operating costs to $0.03 per Mcf. We exited the first quarter with 54 wells waiting on completion, which does not include the 4 wells we are currently completing. In addition, we have over 60 drilling permits approved and ready to go in the Marcellus.

As we evaluate our plans for future operating activities in the Marcellus, it is important to understand the supply outlook for our operating area in the northeast Pennsylvania. While there has been a lot of focused recently on the expectations for a meaningful supply declines across North America, which we do fully subscribe to and believe will impact us positively, we're already seeing that dynamic play itself out in our operating area.

For example, in the six county area we define as northeast Pennsylvania, there was about 8.4 Bcf per day of production in February, compared to about 7.6 Bcf per day in April based on our estimates. Not surprisingly, these the lower production levels have positively impacted the local basis, with Leidy and Tennessee differentials for the month of April coming in at their lowest levels since mid 2013. We expect that trend to continue in May, resulting in our second quarter differential guidance range of $0.50 to $0.55 below NYMEX, a $0.05 to $0.10 improvement relative to the first quarter, and a $0.35 to $0.40 improvement compared to the second quarter of 2015.

While curtailments are certainly driving some portion of this production decline, we believe that curtailments in Northeast Pennsylvania were not as substantial in April, since the cash price in the day market has been about $0.20 to $0.30 better than in February and March. Our reservoir team has spent a lot of time scrubbing the state data for over 4,000 wells in northeast PA, in an attempt to better understand the anticipated production declines in our area, as well as to assess the level of drilled uncompleted wells.

Our engineers built production curves for all of the producing wells in the six county area. Additionally, assumptions were made for non-producing wells, as to whether we thought a well was temporarily not producing for reasons like curtailments, and would ultimately be placed back on production when prices were higher, or if the well would never be placed back on production, due to poor performance or a significant period of inactivity.

Ultimately, we found that even when assuming all shut-in production comes back online after the summer, we could still see a 25% decline from year end 2015 to year end 2016. The question then becomes, is there enough operating activity occurring currently to fill that void, or will the area see exit to exit production declines, resulting in a positive outlook for our pricing next winter? Our best estimate is, at this point, is that approximately 120 wells will be completed in our area this year, and modeling suggests that is simply not enough activity to backfill the declining production we see. This is very positive for Cabot.

Our engineers study also revealed an estimate of drilled uncompleted wells that is significantly less than the 800 plus or minus wells you hear reported by some of the third-party sources. Only three rigs are currently operating in our area, and I do not expect that DUC inventory will grow. In fact, it will be shrinking throughout the year, which is positive as we think about 2017 and beyond. While there will always be some inventory of drilled uncompleted wells, I would remind everyone that the most capital intensive portion of drilling and completing a well is the completion side. Accordingly, I suspect it will take higher prices, healthier balance sheets, and cheaper access to capital before we see a meaningful uptick in completion activity in our area.

In the Eagle Ford, the drilling rig released, was released in early February. The drill team has turned its focus to the completions required to maintain lease obligations. During the first quarter, our team in South Texas completed and placed on production nine wells, with an average completion lateral length of 7,760 feet.

During the quarter, Cabot also completed its longest Eagle Ford well to date, with 46 stages and a lateral length of 11,200-plus feet. Capital efficiency and cost savings continue to be the primary focus, with our Eagle Ford completions costs down by approximately 30%, compared to the same quarter in 2015. At the current strip, our plans for the remainder of the year are focused solely on maintaining all of our leasehold obligations through 2016, and not increasing our operating activity above these minimum levels. However, our anticipated backlog of 15 drilled uncompleted wells at year end 2016 does allow for flexibility.

All right. Now everyone is aware of the recent New York DEC decision to deny the water quality certificate permit last week, pertaining to the Constitution pipeline. Today we are not going to dwell on the specifics of the denial notice, and unfortunately, we cannot expand on the legal strategy going forward, other than to refer you to our April 25 Constitution press release, which clearly refutes the allegations of the New York DEC. Because of this, we do want to remind you of our total commitment to the project, and we remain confident we will ultimately prevail.

Because of New York's denial, we have pushed back the service date for Constitution to the second half of 2018. Moreover, we do want to reiterate that although this additional capacity is important to our long-term plans, we have successfully continued our efforts to access new markets. Previously we announced several new projects that collectively add approximately 450,000 MMBtu per day of new long-term sales and transportation capacity to new market areas. Additionally, we have been very active, with two additional projects that again solidify our long-term growth profile and improve our infrastructure situation. We will be providing updates and details on these transactions in the weeks to come.

Regarding the Atlantic Sunrise, the project continues to move forward on all fronts, particularly on land, regulatory, and permitting side of the project. Our expectations are to receive the draft environment impact statement soon, and per the FERC scheduling notice in March, the final EIS is scheduled for October. Cabot now anticipates contributing $30 million to $35 million to its equity investments in these pipeline projects in 2016, down from the original guidance of $80 million to $150 million.

In regard to the remainder of 2016, we have guided with curtailed volumes for our second and third quarters. Additionally, we are in the process of updating our plans for 2017 and beyond, in light of the recent news regarding Constitution, and the addition of several other projects we are working on. However, I will comment that similar to our plan for 2016, Cabot will be able to economically grow our natural gas production in 2017. While we have a range of outcomes for 2017 at this point, the ultimate level of growth will be the direct result of our underlying expectations for price realizations during the year.

We also anticipate a further acceleration of our growth rate in 2018, in anticipation of the timed in-service of the various infrastructure projects I referred to earlier. These projects will add approximately 1.3 Bcf per day of new firm transportation capacity and long-term sales in 2018, and this figure does not include any Constitution capacity.

In summary, our strong financial position, the lowering of our cost structure, reduced level of industry activity, improving natural gas differentials, and strong portfolio of future takeaway opportunities outside of New York position us well for the future.

And Rocco, with that, I'll be more than happy to answer any questions.

Yes, sir. Thank you.

(Operator Instructions)

Doug Leggate, Bank of America Merrill Lynch.

Good morning. This is John Abbott calling in for Doug Leggate. I apologize, he's on another call. Just two very quick questions. First, with regards to northeast PA, what sort of rig activity, do you think we would have to see in that area to sort of, to stem declines? And then second, looks like you sold some assets in east Texas. Are there other opportunities for portfolio clean up? And also, why don't you think we've seen more consolidation, among the gas names in the current environment? Thank you.

Okay, John. 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 coincident 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 is not, and that number of frac crews up there, is not the level of activity that will maintain it, and 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. And what was the -- I'm sorry, what was the --?

The consolidation in the industry, amongst the gas players.

The consolidation amongst the gas players, I think is a result of the commodity price sitting at, in the first quarter 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 this low 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.

I appreciate it. Thank you.

Thank you, John.

Charles Meade, Johnson Rice.

Morning, Dan, and to the rest of your team there.

Hey, Charles.

I wanted to ask if you could maybe share a little bit more, I guess, you gave us a lot of detail on your Northeast supply. But maybe you could share a little bit more on the conclusions there, or what it suggests to you. And specifically, you guys guided to a tighter natural gas realization in 2Q, but do see that continuing into the back half of 2016? I think I picked up on that from your comments. And does that even tighten it enough, that it raises questions about the economics of new takeaways out of there, if bases got that tight?

Well, I think on the supply side, my reference to a 25% or even 30%, depending on looking at our models decline that is 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 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 a supply side and lack of activity, it is now coming 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 anytime near term. So I do expect to see continued narrowing of the differentials, and I think it's a positive for Cabot.

Got it. Thank you, Dan. And on Constitution, I mean, 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, 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?

Yes. It's exactly right. We have, we have looked at New York's own projections, their 2020, 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 in an industry that endorses renewables as part of the energy mix. We will 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 into consideration the cost 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 difficult set of facts to understand, though they at times are not represented in a lot of the media print

Right. Right. Thanks for that, Dan. And just one clarification, the 1.3 Bcf in new takeaway that you mentioned in your comments, that's in addition to Atlantic Sunrise?

It includes --

No, in addition to Atlantic Sunrise, it is in addition to Constitution.

Okay, got it. Thank you.

[Does not include Atlantic Sunrise].

Bob Brackett, Bernstein Research.

I had a quick question at a strategic level. If you think abut your portfolio, are you currently happy with your portfolio? Does it need any additional changes?

Well, we love the assets, Bob. 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.

Great. Understood. Thank you.

Phillip Jungwirth, BMO.

Hey, good morning. On the two additional projects you mentioned were in the works, how long-term are these, meaning when is the earliest they can contribute to incremental demand for Cabot's gas? And can you talk about what entices these would be tied to, or whether it would be fixed pricing?

Right, Phillip, I'm going to that over to Jeff Hutton.

Yes, Phillip, I really wish this call was a few weeks away, so we can talk in detail about these two projects. One has to do with bridge capacity, and that's capacity that could start as early as next spring. And the duration of that is up in the air at this point. We could make it 1, 2, 3 years, or out 5 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 to 15 year time frame. And it would start also probably late 2018.

Great. And then, 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 at $2 an [M] 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 [FT]?

Well, when you look at the study that we are doing up there, Phillip, and you take into consideration the supply side diminishing somewhat, for Cabot to be able to pick up incremental space in the pipes, I think Jeff is 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

Great, thanks.

Thank you.

Pierce Hammond, Simmons Piper Jaffray

Good morning, guys.

Hey, Pierce.

Dan, I appreciate your prepared remarks. It's very helpful, especially on the gas macro. The NYMEX future strip agrees with you, as gas for 2017 is roughly $3. So what does Cabot look at $3? You're running one 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?

Well, on the response side first, Pierce, you're aware and most others are also, that 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 it 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 the example, we'd only be -- throw out a number, $250 million or so to just kind of keep our production flat, at $3 and if we wanted to just do that, at $3, we would be generating a significant level of free cash flow.

And the ramp up or taking advantage of the opportunity at a higher price is part of our planning process right now, and we're looking at the strip price. We're planning on the infrastructure's 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.

Excellent. And then, my follow-up, and 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?

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%, and rolling forward now to the 7.6%, 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.

Great. Well, thank you very much, Dan.

All right, Pierce. Thank you

Michael Glick, JPMorgan.

Good morning.

Hey Michael.

You all continue to make improvements on the efficiency side in Marcellus, could you maybe provide some color there, in terms of the drivers? And then, on the other side, in the terms of productivity, is there anything you're testing that can drive that higher?

Well, the -- one, as you can imagine with the scrutiny on one rig, and a frac crew in daylight hours, we are able to allocate a lot of man hours towards a limited level of activity. I'll let Steve Lindeman discuss some of the ideas that we're implementing, on not only the Marcellus, but maybe some of the ideas that we have coming through on our Eagle Ford operation also.

Michael, 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 1,000 foot longer lateral. And that doesn't really, in terms of the drilling cost, that's a very efficient portion of the operation. 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 coil tubing rigs that we have on location to drive our average costs down. And 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 worked very hard to drop those numbers throughout the year, and especially quarter over quarter. And the same thing on the chemical side, in the Northeast, we've reduced some methanol uses. We had a milder winter, and in the south, again working on our chemical efficiencies.

Got it. And then the (multiple speakers)

Sorry, go ahead (multiple speakers) The other thing I was going to mention, in the South, we also are putting in quite a bit of electric infrastructure. Right now we have over 50% of our wells on either utility power or on micro grid is which is a significant cost savings from generation.

Got it. And then, I'll try one on the infrastructure side. So I mean, generally in Northeast, we've seen varying degrees of local hostility to 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 in the interest of the public. So my question is, do you see strategic importance in having the courts clarify what the role of the state is, in the pipeline regulatory process?

Well, just from a macro comment, Michael, 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, we fulfill our leave it in-the-ground comment.

I think from a, 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 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.

Appreciate that. Thank you.

David Deckelbaum, KeyBanc.

Good morning, Dan, Scott and Jeff. Thanks for taking my questions.

You bet.

I just want to expand on a few of the other questions you have been asked today. Now first, starting with the commentary around your internal team looked at, I guess, a 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 perhaps pick up now that they don't intend on using? And if so, how receptive are those conversations right now?

David, I'll let Jeff comment. But I know that certainly there has been firm capacity out there that has been discussed, probably even before we've had such punitive pricing and balance sheet stress. But I'll let Jeff comment

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

So although we've been slow dancing this a little bit, only because we think that the timing is getting better, each month it 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 you'll read about in new projects. But there's definitely an improvement in the secondary capacity market, and I just think it keeps getting better.

Got it. And I suppose those agreements would be something that you'd probably want to hammer out before the end of the year?

Sure, yes.

Yes, okay. And then, my next question, just on the balance sheet and free cash, and you updated CapEx today, I think, obviously makes sense not having the pipeline commitments. And it 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 takeaway projects? And I guess, sort of dovetailing on Bob's question earlier, about the portfolio. With excess free cash, and do you start looking at beefing up on other areas, outside of the Marcellus that are in your portfolio?

Dave, this is Scott. In response to your first question, the answer is yes. We would just use it for, for lack of a better word, kind of weather the storm, and see just the ebb and flow. We are modeling it similar to that, with our 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 we still believe we've got, from a rock perspective, we got the best rock 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.

That's helpful, Scott. Thank you. And then the last one for me. I guess, without having you guys cite a specific number on curtailed volumes, could you give us a sense of, perhaps percentage-wise, how much those curtailments that you have internally, have declined from the peak of where it was last year?

Where our internal curtailed volumes were, at the time that we had maximum curtailment? Is that kind of the --?

Yes. Relative to currently.

Well, I think you could look at it, David, just like you would look at the baseline decline. You look at, you kind of look at where the curtailed volumes were, even though you weren't producing at that point in time. As you bring the baseline decline, it's all proportionate to those curtailed volumes.

Okay. That's a good starting point. Thanks, Dan.

Thank you.

Marshall Carver, Heikkinen Energy Advisors

Can't hear you, Marshall.

Marshall, your line is open, sir.

Sorry, most of my questions were answered. But a quick 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? And was there any production to? Thanks.

Yes, the production was kind of in the mid-teens, and it was more the Cotton Valley assets, and not the Haynesville.

Okay, thank you. And the third-party shut-ins in the Eagle Ford, how much did that impact the quarter? And is there impact to the second quarter, or has that all been resolved?

That was about three-quarters of a Bcf, just those alone for us in the South region.

And it was done -- when did it --?

It was down most of the, or half or so of the first quarter, and it's back on line about the April 20 or so.

Okay. Thank you.

Brian Singer, Goldman Sachs.

Thank you, good morning.

Hey, Brian.

You mentioned on the transportation side, you are working on or 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 because projects take us to a different, a different direction, different point?

Well, 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 equivalent 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 levels. 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 as 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.

That's great. And kind of tying that back into some of the efficiency questions on the upstream side, that you answered a question on this earlier. I think you made a reference to some chemical-type efficiencies. And 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 or have tested, or testing any technologies that would significantly improve the, what some would call a green footprint, in terms of reductions in chemical intensity? And do you think that has a place in the Marcellus?

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 a 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, less and except what we put into the formation. So we're confident that our operation using best available technology is mitigating any concerns 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.

Yes, thank you. That, my question was actually more towards these, could best available technologies become even greater, could there be a, any kind of further improvement there? But thank you.

Yes, thank you, Brian.

And this concludes the question-and-answer session. I would like to turn the conference back over to Mr. Dinges and the rest of Management Team for any closing remarks.

All right. I appreciate it, Rocco, and I appreciate everybody's interest in Cabot, and I look forward to a report next quarter. Thank you.

And thank you, sir. Today's conference has now concluded, and we thank you all for attending today's presentation. You may now all disconnect your lines, and have a great day.