Good day, and welcome to the Cabot Oil and Gas Corporation First Quarter 2019 Earnings Conference Call and Webcast. All participants will be in listen only mode. Please note, today's event is being recorded. I would now like to turn the conference over to Mr. Dan Binges, Chairman, CEO and President.
Please go ahead, sir.
Thank you, Rocco, and good morning to all. Thank you for joining us today for Cattell's Q1 2019 earnings call. With me are several members of the executive team. I would first like to remind everyone that on this morning's call, we will make forward looking statements based on our current expectations. Additionally, some of our comments with reference non GAAP financial measures, forward looking statements and other disclaimers as well as reconciliations to the most directly GAAP financial measures are provided in this morning's earnings release.
Cabot shareholders have enjoyed a solid start to 2019. During the Q1, we delivered record levels of operating cash flow, free cash flow, adjusted net income and production underpinned by the continued success from our operations in the Marcellus and our unwavering commitment to disciplined capital allocation and cost control. The 1st quarter net income was 2 $63,000,000 or $0.62 per share and adjusted net income excluding selected items was $308,000,000 or $0.73 per share. This represents a 161% increase in adjusted earnings per share relative to the prior year comparable quarter. Free cash flow for the Q1 was $308,000,000 which was approximately 3.5 times the amount from the prior year comparable quarter and greater than our free cash flow generated for the full year in 2018.
For the trailing 12 months, we generated a return on average capital employed of 20.4% compared to 8.3% for the trailing 12 months as of the end of the prior comparable quarter, representing an increase of over 1200 basis points. This ROCE of over 20% exceeds the current ROCE for the S and P 500 highlighting Cabot's competitive positioning relative to the broader equity markets. Our success for the quarter was driven by higher production levels, improved realized prices and lower operating expenses. Production for the quarter of 2,280,000,000 cubic foot per day was above the high end of our guidance range and represented an increase of 21% relative to the prior year comparable quarter. Natural gas price realizations were $3.35 per Mcf, an increase of 37% when compared to the Q1 of 2018.
Our price realizations before hedges were $0.06 below NYMEX, which was our best corporate wide differential since the Q2 of 2013. Operating expenses decreased to $1.48 per Mcf, a 6% improvement relative to the prior year comparable quarter, primarily driven by lower direct operating expenses, DD and A and interest expense. Given our strong free cash flow generation during the quarter, we ended the period with over $300,000,000 of cash on the balance sheet and a net debt to EBITDAX ratio of 0 point 6 times, highlighting significant financial flexibility or continued return of capital to shareholders throughout the year. On the return of capital front, we announced a 29% increase in our dividend to $0.36 per share on an annualized basis, representing a 1.4% yield. This is our 4th dividend increase in the last 24 months.
We expect to continue to increase our dividend methodically with an intent to grow our dividend over time to a yield that is competitive with the broader market. Our free cash flow generation over the coming years will certainly be able to support this dividend growth even under significantly lower natural gas assumptions should the lower prices occur. We remain fully committed to returning a minimum of 50 percent of our free cash flow to shareholders this year through dividends and opportunistic share repurchases, giving it is still early in the calendar year and we have been in blackout period for the majority of the 1st 4 months of the year. We have not executed on any material share repurchases year to date. However, we fully expect to continue to reduce our shares outstanding throughout the year and have significant financial flexibility to be much more active on that front, especially if we see a continued weakening in natural gas prices that have negatively impacted our share price.
Moving on to our operations for the quarter. Our Marcellus production increased 25% compared to the prior year comparable quarter. During the quarter, we placed 13 13 wells on production, all of which were in March, including 7 of the 13 wells that were turned in line the last week of the month. We expect to place an additional 18 wells on production during the Q2, resulting in a production guidance range for the quarter of 2.3 Bcf to 2.35 Bcf per day or a 2% sequential increase relative to quarter at the midpoint of our guidance range. On the pricing front, we have experienced some weakness in the natural gas forward curve as weather related demand has dissipated in April, which is expected during the spring shoulder season.
However, we believe there may be upside to the current price levels driven by weather related demand this summer that would also coincide with the potential increases in exports to Mexico and continued strength in the demand for feed gas from LNG export facilities. Lastly, on the production front, we are expecting a slowing of growth in the Northeast and Haynesville, which should be supportive for prices from a supply standpoint. The current strip, including actual NYMEX settlement through April implies a $2.75 average price for the year, which is directly in line with our budgeted price. Based on these prices, we expect to generate over $50,000,000 of hedging revenue for the last three quarters of the year. Through a combination of hedges and fixed price deals, we have approximately 46% of our volumes locked in from Q2 to Q4, providing some mitigation of potential downside price risk.
For the full year, we have reaffirmed our 2019 capital budget of $800,000,000 and our production growth guidance of 20% or 27% on a debt adjusted per share basis. At our $2.75 NYMEX budget price for the year, we now expect to deliver adjusted earnings per share growth of 45% to 55%, return on capital employed of 22% to 23% and free cash flow of $600,000,000 to $650,000,000 implying a 6% free cash flow yield at the midpoint of the range. In closing, I'm proud to report one of the best quarters in Cabot's history, which is a direct result of continued operational excellence in the field, which has driven improved capital efficiency year after year, a marketing strategy that has allowed us to access new markets and significantly improve our differentials without increasing our gathering and transportation costs, a continued commitment to cost controls including divesting higher cost properties and maintaining low overhead costs and interest expense, the latter of which is supported by one of the strongest balance sheets in the industry. And lastly, as I stated many times before, but truly feel is paramount to our entire strategic plan, disciplined capital allocation focused on delivering strong returns on and of capital and a competitive growth in the per share metrics.
Rocco, with that, I'm more than happy to answer any questions.
Thank you, sir. We will now begin the question and answer session. Today's first question comes from Leo Mariani of KeyBanc. Please go ahead.
Hey, guys. Just a quick question on your 2nd quarter production growth. It looks like you're bringing on more wells in 2Q versus 1Q. Additionally, a lot of the 1Q wells kind of came on late in the quarter. I guess given that I would have thought maybe the growth would be a little bit higher in 2Q.
Are you seeing a lot of those 2Q well tie ins also come on late? Just any color you have around that would be helpful.
Well, we'll have a number of those wells that are scheduled for May and that's kind of the middle May, so that's pushed out towards the latter part of the quarter. As we bring on these wells and we bring them on systematically. We don't bring on flush production out of the as we unload the wells. So even though we bring them in, say, the middle of the quarter or the latter part of the quarter, we'll still bring them on and we'll see the majority of that increase probably towards the Q3.
Okay. Very helpful color for sure. Any further update in terms of the Upper Marcellus well performance now that you've had a couple more months to kind of view those wells?
No, it'd be a similar comment that I've made previously. We have not seen anything to deter our expectations that the reduction curve, the decline curve, if you will, would be above what we have out there currently as our 2.9 EUR for the Upper Marcellus that is holding true with the early time production curve. And quite frankly, we do expect that, but as prudency would necessitate, we're going to get more production before we make a firm statement on that. But we're pleased with what we're seeing and we're continuing to drill representative wells in that section throughout this year.
All right. Very helpful. I guess just lastly on your stock buyback. Obviously, a little bit less robust this quarter. It sounds like just on your comments, it was really just due to the blackouts that you guys had and some of the restrictions there.
Clearly more of a focus on maybe kind of ramping the dividend. I guess to kind of get to that S and P competitive yield that you're sort of talking about, do you think that's something that could kind of happen by the end of the year? Is that kind of a realistic expectation when you talked about some of the measured dividend growth?
Yes. We look at it in whole. When you think about our buybacks, we had the Q1 and coming into the Q1, as we're all aware, had strong pricing in December into the early part of Q1, a lot of noise. You had some early warming and coming into the shoulder months And also during the blackout period, we thought it was prudent to just let all that settle in. We were focused on the dividend increase.
We had a discussion with our Board that this is directionally where we want to go. So felt comfortable with our our position on buybacks for the Q1 and laying out this dividend increase. And as we go through the year, we'll continue to have Board discussions on how we want to allocate our capital in the form of dividend increases and buybacks. But our comment and our 50% of our free cash flow is I feel certain is going to occur before year end.
Okay. Thank you for the color.
Thank you.
And our next question today comes from Mike Kelly of Seaport Global. Please go ahead.
Great. Thanks.
Dan, industry consolidation has obviously been the hot topic in the space right now. And this has been a leading question. But if I look at Cabot, you guys are really kind of a one commodity and really just a one county levered operator. And I'd love your thoughts on adding diversification to the portfolio and just kind of get your general take on what Cabot's role, if any, is likely to be in kind of a period of increased consolidation? Thanks.
Yes. Thanks, Mike. It's going to be I think you'll continue to hear a lot of the chatter and expectations on the M and A side. When we look at our asset and where how we're located to your point of a single commodity, single basin, single regulatory environment, It's 2 edged sword. We're there, but we're there with the what I think is probably the best natural gas assets in North America.
I think our numbers and financials do reflect that. So looking at what we can deliver with just those assets, manage the risk profile of it being single commodity or same jurisdiction, we're comfortable with that. We're comfortable with how we've been able to manage it and we're comfortable with working through both the regulatory environment and the commodity price expectations that we can still deliver financial results. And when you look at long term and assess from a Board level, strategic level. Cabot has always made decisions that are, I think, beneficial to shareholders to deliver the maximum value and any strategic decision we would make would also take that in consideration.
So if it's good for the shareholder, my job 1, 2 and 3 is to deliver value to the shareholder. And if it's good for the shareholder, my job is to evaluate it. So if it's strategic, it's strategic. If it's doing what we're doing and that's organic growth, delivering value through dividend increases and buybacks and organic growth with a very clean balance sheet. I think we have one of the best looking companies on a macro level and delivery to shareholders that you can find out there with a high degree and level of consistency on delivery.
So we're happy with the cards we have. And again, if there is significant value enhancement in any other direction, then I'm paid to look at.
Great. Appreciate the color. Shifting gears a little bit, Q1, the differential, it's great to see that narrow fairly significantly. Just wanted to get your thoughts on how you see that differential trending throughout the rest of 2019 differentials you head into 2020 beyond? Thanks.
Yes. Thanks, Mike. And I'll let Jeff handle that.
Good morning Mike. Differentials were what we expected in Q1 after Atlantic Sunrise ramped up and basin demand projects came on. So we certainly enjoyed the good Q1. Looking out of Q2 and more short term maybe the balance of the year basis has widened a little bit. We did expect a more volatility in the shoulder months and we're seeing it right now.
I think the same volatility applies in the NYMEX world as well. So we do expect some ups and downs. Looking out beyond that, it's still encouraging. They're way, way better and way tighter than what we experienced in 2016, 2017 2018. So we're pleased with the trend and I think
it's here to
stay. And quite frankly, as we build more in basin demand projects and others do as well. And we see the production, not necessarily decline, but certainly the growth moderate. Our expectations are we're here to stay with these type of differentials.
Great to hear. Appreciate the color, guys.
And our next question today comes from Charles Meade of Johnson Rice. Please go ahead.
Good morning, Dan, you and your whole team there.
Hi, Charles.
I wonder if you could give us a little bit more insider detail. It makes sense to me on your blackout periods. It makes sense that with year end reporting that a lot of the early part of the year is going to be blacked out. But what's it look like or I guess 2Q the 4 part of 2Q for you?
As far as the blackout is concerned?
Right.
Well, we have a consistent parameters leading up into our year end numbers and our quarterly release and as we gather the numbers, we provide notice to all of the, as you put it, insider personnel, including the Board, a bandwidth that's conservative early and we allow for a few days for dissemination of the data post release to end the blackout. So the Q2 is going to be open next week sometime and we'll be free to do what we want to do at that period of time.
Got it. And so I guess where I'm going is the majority of this 3 month window is going to be open to you, which is different from 1Q and that's the message you were trying to give us?
Yes, yes, exactly.
Got it. And then second question, you and this go back to your comment you made in your prepared comments about what you're seeing or what your expectations are from Marcellus for kind of play wide growth in Ditto in the Haynesville. So it seems from my point of view that most operators up in the Marcellus are, I guess, holding rank in the sense that they're we're not seeing a breakout in activity and people going back to outspending. But could you confirm if you're what you're seeing, if that's similar and maybe elaborate on how you expect that to progress through the year?
We have our group up there monitors the equipment activity, rigs, frac crews and get a we get a fairly good feel for particularly in the 6 County area that we focus in, a fairly good level of expectation of the number of completions that would be coming on. And so our comments are with the benefit of that information. We certainly feel comfortable and agree with your comment that there is some rationalization going on by the industry. And I think that is prudent and I think it will continue, Particularly, when you look at the shoulder months that we see, you've seen a fairly good and quick fall off because of the early weather conditions. And that certainly has bearing on capital allocation and intensity of capital allocated.
You also come into this period of the season with maintenance that affects production profiles and forecast, which certainly affects our 2nd quarter numbers a little bit also. So I don't know, we're just we think there will be that rationalization and some of the equipment count indicates that also.
Thanks for that added color, Dan.
Yes. Thanks, Charles.
And our next question today comes from Brian Singer of Goldman Sachs. Please go ahead.
Thank you. Good morning.
Hello, Brian.
Can you or Jeff give us the latest update on the midstream chalkboard, any local demand projects or pipelines out of the region that are moving earlier or later added or subtracted from the schedule?
Yes. I'll turn that to Jeff.
Hi, good morning, Brian. I guess 2 areas on in basin demand. Obviously, it's key on our radar. We are out there looking very, very hard at a number of different things. Nothing to announce today of course, but I would add that we're also being very maybe selective in our approach.
We want to find the right project, the right scale, timing. We also want to find the right project for the community and there's just a lot of factors going into it. We are looking around. We have a lot of leads and a lot of prospects. I'll kind of leave it at that.
But I might add that others are doing it as well. And in the 6 County area up there, I think there's been something like 1 point 4 Bcf of in basin demand added in the last year and a half. Of course, a lot of that was power growth And we're continuing to get calls about additional projects up there, but on the power side, but we'll see how those play out. In terms of infrastructure, I'll just talk about Leidy South to begin with. Publicly, you all will see a filing notice at FERC probably in June on the project.
We've completed pre filing, completed open houses to the projects moving along. I see nothing at this point to move us away from a November 2021 in service on that project. Talk a little bit about PennEast, I think publicly they have said that they'll submit their DEP permit to New Jersey sometime in June. I think they also have said administratively they are complete in Pennsylvania. So that's good.
So we'll see how the DEP and their 401 is treated once it's submitted. Obviously, it could be anywhere from 6 months to a year. And I believe they've stated they'll start construction as soon as they get that final permit. That's about it on the project side at this point.
Great. Thank you. And my follow-up, Dan, as the dividend increase is certainly notable here. What are the key areas of focus for you management and the Board as you try to go through the year and figure out how much more relative to the 50% minimum you would expect to return cash to shareholders? What do you see as the potential range and then the key other areas of competition for cash?
Well, the biggest competition for cash is Scott. He wants to maybe keep that pay off all that debt. Yes. But kidding aside, we evaluate the different process that can be employed in dividend management. There are and buybacks.
There are some that says go ahead and get it ratchet it up to the level that you would want it to be. And from a counsel standpoint a 3rd party perspective, it seems to be a 2% yield on dividend, seems to be the floor when it comes to evaluating the broader market. And on the buybacks, there is the back and forth between opportunistic and just putting in a consistent program of buybacks and what is the most effective process to employ in doing that. So when we have that discussion at our Board at this point in time And again, we've had free cash flow the last 3 years. We are now moving into a clear picture with just Marcellus as our asset, Our predictability with again was just last October with commissioning of Atlantic Sunrise, the certainty of the commodity space and where we think the landing point is going to be, the differences in differential in the Northeast area, we wanted to measure out.
And with that comfort and a clear path for over a decade of being able to deliver free cash flow. I just think and the Board thinks at this point in time, though maybe conservative that representing delivery of 50% of our cash flow in broad including dividends and share buybacks is a messaging to the street that we're going to do it. But we also say that we will give back possibly more than that. And we're comfortable right now taking a gradual step up in the dividend increase and we're comfortable right now just having a opportunistic messaging on buybacks. Could that change in the future?
Sure, it could, because we talk about it every Board meeting. A little bit long winded, Brian, don't know if that answers you specifically, but we do consider all aspects of how we give back capital.
That is helpful. Thank you.
And our next question today comes from Holly Stewart of Scotia Howard Weil. Please go ahead.
Good morning, gentlemen. Dan, maybe the first one just I know you've provided your kind of key forecasted financial metrics at different pricing, but any updated thoughts around your activity levels? Should strip move substantially below this kind of 2.75 level and obviously recognizing differentials are substantially better than they have been when we were at sort of similarly depressed NYMEX prices?
Yes. We have bandwidth of $2.50 to $3 and if it moves substantially below our bandwidth as an average for the year, and any point during the year, we're not going to have a knee jerk reaction to our capital allocation. We'll continue to look at the macro and make some projections on where we think the strip is going to go. But you need to keep in mind that we deliver significant amount of earnings and return to the shareholders even below our $250,000,000 low end that we've used for 2019. I understand the metrics and I understand the cost and I understand the return from our peer group out there.
And I know that if Cabot gets stressed in any particular way, I think there's going to be a self correcting mechanism because Cabot can make money below $2 but fairly confident with my knowledge that there's not going to be a lot of money made below $2 and I think it's going to have an impact on the macro environment.
Yes, understood. And then maybe just one for Jeff on Atlantic Sunrise. I mean, Jeff, I know we've talked about your equity investment there and you'd previously mentioned looking to see that final project kind of move forward on Atlantic Sunrise. So maybe any updated thoughts on your divesting of that equity investment?
Holly, this is
Scott. As we said when we invested both in Constitution and Atlantic Sunrise, our motivation was to have a seat at the table as part of the decision making process. And that served us well obviously with one very positive result, one still yet to be determined. But long term for the company, it's they're not going to be either pipeline or it's going to be part of our assets going forward. We continue to kind of monitor the marketplace.
And when we feel it's right, we'll explore the opportunity to sell that asset. So right now, more to come. We're just kind of assessing that at this time.
Great. Thanks, Scott.
And our next question today comes from Jeffrey Campbell of Tuohy Brothers. Please go ahead.
Good morning. Congratulations on the strong quarter.
Thank you.
My first question was just it looked like that the Q1 2019 free cash generation was greater than what had been expected just looking at the natgaspricerelationships that you've got on Slide 10. I was wondering if it was that extra boost from the very narrow differentials that you enjoyed in the quarter or was it something else?
I think it was a combination of both. It exceeded our realized price expectations and we did see the significant narrowing in the differential. It was a combo.
Okay. Thanks. And another kind of higher level question. When Cabot's asked about M and A or exploration, it seems like the assumption is always that it would be about oil and be in other basins. I was just wondering if you ever look for other dry gas opportunities within Appalachia.
And I realize your lower Marcellus acreage is clearly the best, but there are some other dry gas areas in Northeast PA that are starting to show dramatic improvement. So I wondered if that's something you keep an eye on.
Yes. We monitor all the activity up there and we do keep an eye on it. From a decision standpoint and how we monitor or consider capital allocation or strategic opportunity, we look at what the financial returns would be of any investment we've made at agnostic, quite frankly, to the commodity. If we feel like we can deliver significantly more of the same than if it comes through natural gas asset or oil asset, we're indifferent. The benefit if you do get out of basins, the it mitigates the single commodity.
If you do also get out of basin, it would probably be an oil consideration also, which also is not only the commodity differential, but it is also out of the jurisdictional confines of PA. So we look at both, but 1, 2 and 3 is what deliveries of the financial metrics would occur if we did anything.
Okay. Thanks very much.
And our next question today comes from Michael Hall of Heikkinen Advisors. Please go ahead.
Thanks. Good morning.
Hey, Michael.
Solid quarter. Just curious maybe if you could talk a little bit about hedging philosophy and just kind of how you guys are thinking about that as you keep progressing forward on the payout strategy and the path you've laid out. How are you guys thinking about hedging and how might that evolve over time?
We went into the 2019 with virtually no hedges and we ramped up as we have currently and where we stand. We felt like that was an inflection point. The market responded to some of the weather that we had and we took advantage of some of that. Obviously, prefer offensive hedges prior to defensive hedges. We will be opportunistic and we will lock in what deliverables that we have promised if in fact the market would provide that to us.
The runway on some of the hedge is somewhat limited by just the depth of it. You can go out there a good ways, but it's not necessarily always at the price point that we would like to see. So if there is not a lot of depth and then we're it limits our participation, but we do see numbers that we appreciate and it helps where we think the macro market will go and it improves our line in that regard, then we continue to layer in that opportunity to mitigate.
Okay. That makes sense. And I mean, is there a kind of minimum level of hedge that you guys are targeting over time? And do you kind of bias towards hedging on a differential versus at NYMEX or any additional thoughts on that?
Well, we look at it every way, Michael, on how we might place those hedges and where we think the opportunities would come. And certainly now with the a little bit different index points that we reach today, then we have that added flexibility. There's no minimum hedging on our books, we're not going to because we set a minimum, we're not going to try to achieve a minimum. If in fact though, back to my point, if it looks like that we can improve our life from our forecast and the market would give that to us, then we're going to be active in the hedge market. And the same holds true, we really have no minimum that we'd like to get to and we have no maximum that we would be prepared to get to also.
If we see an opportunity to lock in the majority of our volumes under hedge, we would do that.
That makes sense. And then I was also curious just on the operational side, as you kind of look at the asset quarter to quarter across the year, How do you think about downtime relative to like what maybe like maximum potential productive capacity of the completed well set would look like. What's that kind of running on average as you think about things like offset well shut ins, you mentioned maintenance on pipelines, things along those lines. How should we think about kind of downtime assumptions as we build things out?
Well, we build into our forecast a percentage of downtime and as a roundabout number, say 10%. And that downtime though does include some of the known maintenance scheduling that Jeff provides through the pipelines that will be incurred and dates are set for preventive maintenance and pigging operations or whatever the case might be. So we incorporate that into our sales forecast, if that answers your question.
Yes, that does. And I'm assuming that also things like offset well shut ins. I mean, if it's 10% overall, how much is like known scheduled maintenance versus just kind of a buffer for potential operational deltas, if that makes sense?
Yes. We have our historic look of the offsets and effects on offset wells or the time that we might shut in an offset well during a fracking operation, we take that into consideration.
Okay. That's helpful. Thanks guys. Appreciate it. Thank you.
And our next question today comes from David Deckelbaum of Cowen. Please go ahead.
Good morning, Dan, Scott, Matt. Thanks for taking my questions.
Hey, David. Thanks.
Just that and maybe a little bit more on the minutia, but in prior plans you did allow for some well cost inflation over time. How do you see that progressing now through the balance of this year going into next year? And I guess as you think about your footage costs on just even benefiting from longer laterals, how long do you see that progressing for? And where you could keep that footage costs sort of flattish here?
Yes, we anticipate between now and the end of the year a relatively flat service cost. Majority of our costs, as we've mentioned before, David, are tied up in annual contracts, well, in both the biggest components rig and pumping services. So we expect fairly flattish cost. We continue to try to increase our lateral lengths based on the geology geography out there and we'll continue to do that. We kind of like the zip code we're at from an efficiency standpoint.
And but we do continue to try to squeeze out everything we can if it feels the guys up there in the North region feel like that their process and all the different not only the operational progress that we've made in the past and learning we've had in the past, but any new ideas that they have out there, which we do and are trying several right now, that's not ready for prime time, we'll implement and hopefully we can continue to gain the efficiencies that we've been successful in doing in the past.
I appreciate that. And you guys sort of reaffirms the differential guidance for the year. Do you still sort of see that or use it as your base case going into 20 20? Or as you look at some of the in basin demand projects or other efforts to kind of reduce some of the or relieve some of the impact around Lady. How do you see that differential shaping up for you at the corporate level going into 2020?
Yes. We have given our guidance and feel like going into 2020, we were going to be in a similar area, at least with our expectations today in the similar area. And it ties back to Jeff's comment about some of the conversations that we have and are having on in basin demand projects. It also ties into what we think others are having in in basin demand projects and the overall macro position on equipment and what we anticipate will be strong rationalization by the operators up in that neck of the woods, we do anticipate the differentials to stay in the same range that we are today.
Appreciate the responses, Dan. Best of luck.
Thanks, David.
And our next question today comes from Kashy Harrison of Simmons Energy. Please go ahead.
Good morning, everyone, and thank you for taking my question.
You bet.
So just one quick one for me. Dan, earlier you highlighted your expectation for a slowdown in both Pennsylvania and the Haynesville. And you talked about what gives you confidence that Appalachia is slowing down. But I was just wondering if you could share some more color on what gives you confidence that the Haynesville might be slowing down as well? Well,
the when you look at it, it's at approximately 10.5 or so, 10 Bcf a day at this point in time. And in PA, we look at the level of equipment activity out there. And in the Haynesville area, as you're well aware that the majority of the operators there right now are private operators and activity driven through the private sector. And I think the idea of continued allocation and particularly if you get a soft spot into the strip and you get a reduction in the natural gas price as we're seeing right now, it would be my bet bet contribution at the levels that they had seen going into the end of 2018 and ramping up with several objectives in mind, whether it would be to increase production because of anticipation of higher commodity price or increasing production with the idea of IPOs opening up, I think that was an activity driver and could still be an activity driver. But in that combination, I do think there is a likelihood that there will be a little bit less activity as we move forward at the levels that it's at right now.
And our next question today comes from Jane Trotsenko of Stifel. Please go ahead.
Good morning. I have a question for Jeff. Atlantic Sunrise is obviously running full. I'm curious how much spare capacity do you see available on Millennium and Tennessee pipelines?
Okay. Well, it obviously it varies quite a bit and but from a high level, we added the in basin demand kind of offset any kind of production growth over the last couple of years in Northeast PA. And you take a look at some of the Southwest PA volumes that are now headed out on Rover and Nexus and some of the Columbia Express projects and other new projects. And then you take a look at Sunrise and the 1.7 Bcf that was probably removed the majority from Transco and from Tennessee and a little dab from Millennium. And then look at some of the new demand that Millennium added, the new competitive power plant in New York.
It all adds up to spare capacity on the interstates. Putting a definitive number on it is difficult because we believe there were spare capacity in these pipes before anything I just mentioned. So it is a moving number, but 2 to 3 Bcf a day of spare capacity is not out of the ballpark.
That's exceptionally helpful. I'm curious, how much appetite does Cabot have to grow production in basin given the numbers that you have just mentioned?
Well, we're all looking at Chaudhary who's going to
answer this. But I think one
of the things that when you look back even 6 months ago, right at the time of Atlantic Sunrise coming on and you picked up on the fact that a lot of capacity was vacated to fill that obligation and rightfully so for better price points. We Cabot did in February come out with a little bit lower of a guidance both on the capital side and on the production side because our motivation is simply not and the market's motivation is not to chase growth. It's more of a moderated growth. Obviously, in 2019, Cabot has outsized growth just because of the timing of that bill of those new projects. But a more moderate growth profile going into the future is what's Cabot's plan at this point in time.
We will defend market share as we've said before if we see the industry starting to backfill those in any great way. But right now as an earlier question indicated, everybody's kind of sitting has a very disciplined growth plan in front of them either to hold certain volumes flat and grow other places. There's no macro push or push from the peers for us to change our growth profile in any way at this point in time and it reinforces our discipline and our capital allocation at this point.
This is a very good answer. The reason why I'm asking is, we obviously have backwardation in the forward curve pricing, right? And then we have production growth that needs that needs to offset that backwardation in forward curve pricing. Very often, what we see is that the earnings trajectory is kind of flattish as a result of this backwardation in forward cap pricing. I'm just curious if you guys are thinking in terms of growing earnings trajectory over the following years or maybe just keeping production more moderate and offsetting the backwardation in the forward curve pricing?
Well, we plan on as Scott said, we plan on having a measured growth on an organic basis. We plan on augmenting growth on a per share basis with our return of capital to shareholders. And from a program perspective and confidence level of what we deliver, we feel like that measured growth and a capital allocation program that allows for 1, that particular growth and the amount of cash flow generation to that yield perspective, which is in 2019, we anticipate around 6%. We think that is a good landing point at this stage. And with the additional giveback to shareholders, we think that we will be able to attract incremental dollars from outside of a traditional energy investor and compete with the broader market.
So from a design standpoint, without having issues with our and uncertainty attached to our program, keep in mind, we're doing this with 3 rigs and 2 frac crews. So the complications of a operation is very, very low and our results are very consistent. So we feel good about that. How we manage this financial side is along the lines that we've discussed and we'll continue to be able to do that again into the next decade.
Got it. That's it for me. Thank you so much.
Thank you.
Ladies and gentlemen, this concludes our question and answer session. I'd like to turn the conference back over to Mr. Dinges for any final remarks.
Thank you, Rocco, and thank you for your interest in Cabot this morning. And as a closing comment, the good news, assuming you like disciplined capital allocation, earnings and production growth, free cash flow, share buybacks, increased dividends. If you like all that, the good news is that you expect more of the same from Cabot in the future. So thanks again. We look forward to the visit next quarter.
And thank you, sir. Today's conference has now concluded. We thank you all for attending today's presentation. You may now disconnect your lines and have a wonderful day.