Good morning and welcome to the Cabot Oil and Gas Corporation 2016 Year End and 4th Quarter Earnings Conference Call. All participants will be in listen only mode. Please note this event is being recorded. I would now like to turn the conference over to Dan Dingus, Chairman, CEO and President. Please go ahead.
Thank you, Anita, and good morning all. Thank you for joining us today for Cabot's Q4 and full year 2016 earnings call. With me today, I do have members of the Cabot's executive team. On today's call, I will be referring slides from the earnings presentation we posted to our website this morning, which highlight our operational and financial results for 2016 as well as our plans for 2017. Before we get started, I would like to move to Slide 2 of the presentation, which addresses our forward looking statements.
Please note that we will make forward looking statements based on current expectations as well. Also, some of our comments may reference non GAAP financial measures, forward looking statements and other disclaimers as well as reconciliations to the most directly comparable GAAP financial measures are provided in both the earnings release and this presentation. Now we'll move to the 2016 highlights on Slide 3. 'sixteen was another positive year for capital oil and gas, especially in light of the lower commodity price backdrop we navigated through for a significant portion of the year. Our plan for the year was to deliver returns focused production and reserve growth to invest capital prudently while targeting a free cash flow positive investment program and to continue to improve our top tier cost structure and to maintain strength of our balance sheet.
I'm confident to say that we executed across the board on all these goals: Cabot grew production and proved reserve by 4% and 5%, respectively, from a capital program that was over 50% lower than 2015. Despite lower realized commodity prices for the year, which resulted in Cabot's lowest realized natural gas price in its history, we were able to deliver our production reserve growth while generating positive free cash flow. That is quite an accomplishment. Our continued emphasis on cost control was demonstrated by our record low all source binding cost of $0.37 per Mcfe and our 11% year over year reduction in cash operating expense per unit. A significant portion of the reduction in our cost structure was driven by internally sourced operating efficiency gains that will remain in place regardless of changes in the service cost environment.
Balance sheet remains strong with approximately $500,000,000 of cash on hand and approximately $1,700,000,000 of available commitments on our undrawn credit facility. During the year, we reduced our debt outstanding by almost $500,000,000 by utilizing a portion of the proceeds from our equity issuance in early 2016, resulting in a significant reduction in leverage metrics throughout the year. On the operational front, we announced an increase in our Marcellus EUR to 4.4 Bcf per 1,000 foot of lateral, improving our peer leading EUR in Appalachia. I plan to discuss our updated Marcellus EUR further in the call. Now let's move to Slide 4, where we have highlighted our production and reserve growth over the last few years.
You can see that we have averaged a 15% 16% compounded annual growth rate for production reserves effectively over the last 3 years, while our 2017 production growth guidance of 5% to 10% is slightly below our historic growth rate as we await new takeaway capacity in the Marcellus, we are forecasting our discretionary cash flow to double this year based on recent strip prices, which is driven by significant improvement in cash margins due to higher realized prices and lower operating 18 as new infrastructure is in place throughout Appalachia. While we have not officially guided to 'nineteen production levels, reserve front, I would emphasize that our proved developed growth has outpaced our total reserve growth, highlighting that growth is coming through the drill bit and is not a function of adding excessive levels of proved undeveloped reserves. Now I'll flip to Slide 5 through 7 kind of cover those all at one comment. They highlight the continued improvement we have seen in our drilling completion and operating cost over the last 3 years, cost reductions our operating team have achieved in both the Marcellus and Eagle Ford, which are represented on Slide 5, have translated into significant improvements in our mining cost and our cash operating cost as highlighted on Slides 6 and 7, respectively.
Slide 8 illustrates our capital budget and operating program for 2017. As we highlighted in the press release this morning, we have increased our total program spending for the year from $625,000,000 to $720,000,000 which includes an $85,000,000 increase for additional Eagle Ford activity to capitalize on the higher prices and most importantly improved well productivity, a $20,000,000 increase in equity primarily for additional drilling activity driven by a $15,000,000 increase in the Marcellus, primarily for additional drilling activity driven by faster drilling times. These increases in capital are offset by approximately $25,000,000 of savings from additional Marcellus drilling efficiencies. We plan to spend $610,000,000 of drilling, completion and facility capital in 2017, of which 67% will go to the Marcellus and 33% will go to the Eagle Ford. This will fund the drilling and completion of approximately 90 net wells.
We plan to exit 2017 with 45 DUCs, of which 35 are located in the Marcellus, positioning us well for accelerating production growth in 2018 upon the in service of new takeaway capacity. Moving to Slide 9, which contains a reconciliation of the updated capital budget to the preliminary budget we discussed on the Q3 conference call referencing the previously mentioned changes in the capital in capital for the year. I would also highlight that despite this increase in capital spending, we are currently forecasting approximately $250,000,000 of positive free cash flow for the year based on recent strip prices. Additionally, while our production growth guidance of 5% to 10% remains unchanged, our year over year oil growth guidance of 15% is substantially higher than the 0% oil growth contained in our original budget. This increased oil growth moves us higher in our production guidance range and allows for more flexibility around curtailments of the Marcellus during the year if warranted.
However, based on current price expectations, we do not expect curtailments to be a concern. Moving on to the Eagle Ford operations, Slide 10. During the second half of last year, we began testing new completion designs in the Eagle Ford to determine the impact of increased proppant loading, tighter cluster spacing, diversion technology. The wells on this slide do a great job highlighting the productivity gains we are seeing from our enhanced completions. The results from a 3 well pad that was completed last year are significantly outperforming the results from an offset pad that was completed with an older completion design.
Additionally, you can see that well 1, which was recently completed with £1800 of proppant per foot is outperforming the other 2 wells from the same pad that were completed with slightly less proppant. While the production history is still limited, we are encouraged by the result and plan to implement enhanced completions throughout our program this year. On the left side of Slide 11, we highlight the impact of our enhanced completions on our Eagle Ford returns. At today's well cost, our average 9,000 foot lateral generates a rate of return over 60% at a $50 per barrel realized price, which is about what we are realizing currently. Like all of our industry peers, we anticipate some level of cost inflation this year and are budgeting this inflation into our well cost for the second half of the year.
You can see that even when assuming inflationary pressure on well cost, our returns are still above 45%. Based on the improved economics and the expectation of higher oil prices later in 2017, we have increased our spending in the Eagle Ford to help pivot this asset back into growth mode as opposed to holding a pattern it has been in, in the last couple of years. Accordingly, we anticipate growing our exit oil volumes this year by 50% as opposed to the 5% we forecasted in the original budget. Heading over to Marcellus and turning to Slide 12, we have plotted the average cumulative production results for our Gen 4 completions compared to our prior type curves of 3.8 Bcf per 1,000 feet and our new type curve of 4.4 Bcf per 1,000 feet. While our sample size is still limited with only 21 wells based on production data we have to date and the fact that these 21 wells were drilled in the north, south, east and west, we are very confident that these are repeatable across the field.
While it is very well understood across industry and investment community that Cabot's wells in Northeast Pennsylvania are some of the best wells in the country, Slide 13 illustrates how our EUR stacks up against other natural gas operating areas across the U. S. In fact, our 4.4 Bcf per 1,000 seat is double that of some of our peers who have been touting their technical expertise on the completion front. We continue to be impressed with the improvements in well productivity we see year after year and are in the process of testing other enhancements to our well design to further improve our economics. Slide 14 demonstrates how our increasing EURs, our improvements in well cost and better realized pricing are impacting our economics.
We originally budgeted $7,900,000 for our 8,000 foot lateral gen four well cost back in October of last year. However, we are currently averaging about 10% lower due to improved operating efficiencies. Approximately 75% of our costs are locked in under term contracts, so we are anticipating only a slight increase in well cost by year end. With this anticipated well cost, our rates of return at the current Righty strip meet or exceed any return we have seen across the industry. Moving on to Marketing and Infrastructure, Slide 15 shows Cabot's monthly realized natural gas prices before hedges, highlighting the significant improvement we have seen in pricing as we entered the winter heating season, while 4th quarter pricing was greatly improved relative to the 1st three quarters of last year, the Q1 of 'seventeen has been even better, driven by strong January February.
While the strip has pulled back as of late due to unfavorable weather forecast, we are still forecasting a substantial improvement in year over year realized prices driven by higher NYMEX prices, tighter basin differentials and a strong portfolio of fixed price contracts primarily for the summer season. As the title of Slide 16 indicates, 'eighteen will be an inflection year for Cabot both in terms of infrastructure additions and for our growth story. Moving to the left moving from the left to the right of the slide, Oron, Moxie and Lackawanna all remain on schedule. Oron received FERC certificate on February 2 and is expected to begin construction this summer. Our 2 power plant projects are currently under construction and on track for an in service date listed on the slide.
As you're aware, Atlantic Sunrise has reached several milestones since we last spoke, receiving the FERC or the final environmental impact statement on December 30, 2016
and the
FERC certificate approving the project on February 3. The next steps for Atlantic Sunrise, including finishing up permit work with the Pennsylvania DEP and the U. S. Corps of Engineers and receiving the FERC notice and we need to receive the FERC notice to proceed with construction. We expect all final approvals to be received by mid summer and construction to begin shortly afterwards.
The insert estate remains mid-twenty 18. Based on the recent progress that was made on these projects, we remain extremely confident in delivering on our production targets for 2018. The PennEast project continues to make progress and is expected to receive its final environmental impact statement in April, while Constitution Pipeline is still awaiting an answer from the 2nd Court of Appeals for permission to move forward. We expect news regarding Constitution status later in the second quarter. As the slide illustrates, upon in service of all these projects, capital will have the ability to double production volumes from its 20 16 exit rate.
As we have communicated in the past, the pace at which we fill this capacity with incremental growth volumes will ultimately be dependent upon the market environment. I will also highlight that our marketing team continues to identify new opportunities to increase Cabot's growth trajectory out of the Marcellus as evidenced through addition of a new 3 year sales contract of $150,000,000 per day on Atlantic Sunrise that was announced at the end of last year. Now we'll move on to Slide 17, which highlights the anticipated improvement in our realized pricing upon completion of the previously mentioned projects. We expect our overall realizations to improve for 2 primary reasons. 1st, the volumes that are shipped on these new projects are expected to receive favorable pricing in the new markets that we are accessing.
2nd, we anticipate our volumes that remain in the local market will see an improvement in realized prices as a result of tightening of in basin differentials from the addition of new large scale projects like Atlantic Sunrise and PennEast and an increase in local demand from the addition of numerous new power plants in the Northeast operating area. Local demand could increase in excess of over 1 Bcf per day beginning as early as January 'nineteen from power plant generation alone. I would also like to highlight that while our forecasted differential improved significantly between '17 'eighteen without adding material amounts of transportation expense, our differentials are expected to improve even further in 2019 as we will receive the full year impact of the projects that were placed in service intermittently throughout 2018. Not to mention, if Constitution is placed in service in 2018 or early 2019, that will have an even further positive impact on pricing as those volumes will reach favorable markets in the Northeast. Another takeaway from this slide that I would like to add is that for 2017, 36% of our volumes are locked in under fixed price contracts at a weighted average price of $2.29 per Mcf, which implies a rate of return greater than 150% for our typical Marcellus well.
These volumes would typically be exposed to the local Northeast Pennsylvania indices that averaged about $1.30 in 2016, so we are very pleased with this portfolio of fixed price contracts. Finally, on Slide 18, we have attempted to address the most commonly asked question to get we get from our certainly a class problem to have and most companies would be envious of our position. We have said time and time again that we believe we can ultimately generate the most shareholder value by delivering returns focused production and reserve growth, and our current organic 5 year plan delivers on this strategy. With that being said, we will continue to evaluate new opportunities, both internal and external, to identify new platforms for future growth that compete for capital internally and provide competitive full cycle economics. Additionally, we plan to continue to evaluate returning incremental cash to the shareholder, most likely through increased dividend and potentially reduce our debt levels over time as maturities come due.
With the organic growth program we have teed up, you can rest assured that we will remain as disciplined with our capital as our track record has demonstrated and only look to invest capital if we believe it will create long term value for our shareholders. So with that, Anita, we will go ahead and open the call up for questions.
Our first question comes from Holly Stewart with Scotia Howard. Please go ahead. Good morning, gentlemen.
Hello, Holly.
Maybe Dan, just picking up where you left off on the uses of free cash. I see one of the things on the slide deck says including new outlets for growth in the Marcellus. Can you just maybe give us a little color there? Is that new projects or more power plant deals or more acreage? Just kind of some thoughts there.
Well, Holly, it's on just a broad comment. I'll back up to my thoughts on the full cycle returns. So all of those that we mentioned, whether it's not new acreage, but it looks like that we can facilitate our longer laterals or some of the offset acreage, which would not expand very far from our core assets and that's just because of the results we see in our core, we would entertain an idea looking at that type of opportunity. I don't put much weight on the capture of that opportunity simply because there's not a great deal of acreage that would fit our model. In looking at other growth areas though, and I can flip it to Jeff, but we do continue to look for arrangements that would allow either additional firm in places or in basin projects to remove some of the gas from the basin and get to different price points.
Jeff? Sure. Holly, in addition to that, we have a very active program in and around our gathering system in Susquehanna County for more additional on what we call on system sales. We picked up some small loads that have to do with compressed natural gas. We're looking at some small methanol facilities and some other demand projects in and around our gathering system that typically would not include interstate pipeline commitments.
On top of that, we still think we have an opportunity with PennEast volumes maybe growing our presence on that pipeline. So lots of things going on.
Okay, great. And maybe Jeff as
a follow on to that, I
was just trying to understand Slide 18, you've got a lot of fixed price sales agreements. I'm assuming those are short term. Can that work into that 2018 column?
Absolutely. We expect to continue our fixed parts program really as opportunity permits. Those volumes have to do with the program for the winter 2016, 2017 and also summer 2017.
Okay. Great. And then maybe just one quick follow-up. Slide 14 shows the drilling completion costs where you've essentially locked in the majority of your program for 2017. How does 2018 look at this point?
On the I'm sorry, I was not what on the please, Ali, I'm sorry.
Just on the slide that shows your locked in cost, I think it's Slide 14. This is 73% of drilling, 78% of completion costs are locked in. Just wondering how 2018 was looking so far?
Well, 2018, we have not locked in cost in 2018. It's certainly our plan to discuss the win win arrangement we can find with the service providers to lock in cost at the appropriate time.
Got it. Thanks, Owen.
Thank you.
Our next question comes from Pierce Hammond with Simmons. Please go ahead.
Good morning and congrats on a great 2016. My first question is on Slide 17, it's very illustrated differential. Should we think of that as guidance or kind of soft guidance for 2017 2018 at that $0.75 $0.50
Yes. We have both with Jeff and Matt have both looked at our anticipated forecast and provided our best guess on a weighted average basis, and that's exactly what that slide illustrates.
Great. And then congrats on the success with the Gen 4 completions. Do you feel like you're getting towards the end of the line on improvements? Or do we see continued improvements? And can we see like a Gen 5?
And then furthermore, in the Gen 4, if you could, could you be a
bit more specific about some
of the things that you're doing either on the specific sand loadings or stage spacing, etcetera?
Okay. First, just a macro comment, Pierce. The question about efficiency gains, I think, is an industry question. You can ask all operators with the improvements that you see in every diversion technology, all of those different combinations are being tried throughout industry and you've seen significant improvements. And we continue to see those improvements also.
Some areas are more conducive to response from those improvements than others, But we do think that with our continued tweaking and the ideas that we have pilots ongoing right now with another whether it morphs into a Gen 5, Gen 6, Gen 7, we will come out with the results if we show positive impact. But I think the entire industry is continuing to find ways through technology to extract more oil and gas out of the ground and we're no exception.
Great. And then my last one, Dan, is on Slide 14, you did a good job of outlining the percent of drilling costs and completion costs in the Marcellus that are fixed or locked in for 2017. Have you done the same sort of thing in the Eagle Ford?
Well, we only have a small percentage of our cost or the oil hedged right now, but we do have some costs that are locked in on the Eagle Ford steam. Why don't you explain Steve Randleman can go over what we've done in the Eagle Ford.
So Pierce, we've got the drilling contract committed for this year and our completion cost for the first half of the year and that's where
we're modeling a little bit of a
step up in cost for the second half of the year. Great. Thank you very much.
Thanks, Peter.
Our next question is from Brian Singer with Goldman Sachs. Please go ahead.
Thank you. Good morning.
Hi, Brian.
On the Eagle Ford, is the increase in activity here simply a drawdown of inventory at a faster rate? Or is there a more meaningful change in the inventory? I know you highlighted some of the better economics as well. But is there any shift in inventory or any other more exploratory measures you're taking place on the oil front?
Well, I'll make a comment, then I'll turn it to Steve again. But looking at the Eagle Ford, we along with, again, industry as a whole and the Permian operators have where the majority of the activity is, has illustrated how much can be done in the oil windows to improve recoveries significant increase in the Eagle Ford, but we did see significant increase that we felt warranted with the increase, we felt it warranted the additional capital and to grow that liquids volume we've seen and what we've been able to get out of that Eagle Ford right now. Steve?
Yes. So Brian, like you mentioned, part of it is our increased well performance with the next generation to completion. And then obviously, we spent a significant time last year really working to drive both our capital cost and our operating cost down. As far as the gross inventory, that remains the same. But obviously, we continue to look at offset opportunities.
We'd love to try and bolt on to our acreage if the opportunity arises.
Steve, you might make a comment of what we have done and some of the savings we're seeing now that will remain with us in the education and well.
So let me start on the drilling side. About 60% of the decrease in our cost related to let's go back to 2014 are items that should stick with us. We're drilling longer laterals. Yesterday, we just or 2 days ago, just drilled 4,000 foot in the lateral section on a well. So we're really working to improve our penetration rate.
On the operating cost side, in 'sixteen, we worked quite a bit on electrification. And right now, we have over 90% of our wells on either microgrid or predominantly on utility power, which is a significant LOE reduction. And then we're just seeing benefits. We are working with another partner to lay some saltwater disposal lines in the southern part of the field, and we're seeing some significant benefits in reduced saltwater disposal cost on those properties. Great.
Thank you. And then shifting to the Marcellus, just wanted to confirm that does the new EUR apply to the average or the entirety of the remaining Marcellus inventory? Or are there any regional or other limitations? And does your assumption for well spacing stay the same?
Well spacing stays the same, Brian. And back to my comment that the sample pool we have are strong from well locations that are on the far east side of our field, far west side of our field and the north and south. So we do think that the application of our Gen 4 EUR per 1,000 is appropriate for the field.
Great. Thank you.
Thank you.
Our next question comes from Anthony Diaz with Raymond James.
Please go ahead. Hi, guys. Thanks for taking my question. I was hoping you guys could help me out. And you guys talked about the translation to the 4.4 Bcf, the 1,000,000 foot lateral on the Lower Marcellus.
I was wondering if you guys could talk me through kind of how should we think about that for the Upper Marcellus if it's the same translation? And then just kind of on what the well mix is on, say, a ten well pad between the Upper and Lower Marcellus as it stands today?
Right now, we are affecting our completions in the Lower Marcellus. We have a number of wells and a number of portions of the wells that have been completed in the Upper Marcellus and the portions of wells would be in the curve and or as we a little layout our lateral in the lower portion, we purposely have designed wells that would allow us to continue to gather data in the Upper Marcellus. But as far as our full development program, we are concentrated as any crude operator would, concentrated in the lower Marcellus at this point in time and then we'll work up into the upper Marcellus at an appropriate time later.
Okay. Yes, thanks for the clarity there. And then last question, it kind of goes to the question before me. How should we be viewing what is the read through on sending more capital to Eagle Ford as opposed to reallocating that into Marcellus? I mean, the returns that we're seeing in Marcellus seem to really blow those out of the water in the Eagle Ford.
Is it seen as a function of kind of outlook on the macro environment kind of holding us off till more pipe comes on? Or is this commodity hedge? How are you guys thinking about it?
Yes. The macro environment is dictating today what we can do with the Marcellus. We have been in a kind of what I'd call holding pattern even though we're generating decent growth and we can with the less than $400,000,000 we can generate growth and both production and reserves and still generate free cash. But in a situation that would have new infrastructure and allow us to grow, keep in mind that our capital intensity necessary to grow those volumes into our anticipated infrastructure build out is not that capital intensive. It doesn't take a great deal of capital to be able to drill the number of wells, complete the number of zones that we need to increase our production an additional Bcf a day.
Rather unique in industry to be able to say that, But the production volumes and our forecast generates so much free cash that there's not that opportunity to because of the low capital intensity, there's not the opportunity to redeploy it all into the Marcellus. I can assure you every MCF that we can put in a pipeline up in the Marcellus, we're going to do that and we'll have ample funds to be able to fulfill that objective. But when we look at our cost of capital of less than 8 percent and you look at a 60% return, we think right now with having a 0.5 $1,000,000,000 on our balance sheet in cash and a 1.7 $1,000,000,000 available on our undrawn credit facility, we felt like investing those funds for a 60% return made sense.
All right. Thanks, Scott. Appreciate the color.
Thanks. Thank you.
Our next question comes from David Deckelbaum with KeyBanc. Please go ahead.
Good morning, Dan and Scott. Good morning, everyone. Thank you. Just wanted to follow-up. I know a lot of people have asked questions about the allocation between Eagle Ford and Marcellus.
Just kind of curious what led to the decision that 1 rig type program was correct for this year in the Eagle Ford given the free cash? Is it sort of a wait and see with more of the enhanced completions? And then based on success as we could see further activity there? Because you also mentioned that you're looking at potential bolt ons and inventory expansion as opposed to perhaps regrowing this asset towards monetizing at some point? Just trying to get the thought process around why 1 rig was kind of the right step for this year there?
Well, a couple of things.
1, when we put together our initial budget in October of 'sixteen, it was not as pleasant of environment on the gas side or the oil side. And our values used on commodity pricing dictated with our methodology of putting together a program within cash flow, we felt like that we would only have a minimal amount of activity in the Eagle Ford. As you continue to see a little bit of price improvement both on the oil side and the gas side, we felt that the and with having a little bit more time on the completions that we've talked about, the enhancements to the completions that we've talked about, we've had a little bit more curve fit on the efficiency gains in that regard. And so from October to February, we decided that it was prudent and we felt comfortable with the commodity price where we are that we would allocate the funds to the Eagle Ford.
I appreciate that, Dan. And Jeff, just a question for you on the fixed price contracts. You talked about these are sort of short term to address winter and summer seasonality. Can you give me sort of an idea of how much that component becomes in terms of percentage of gas sold in sort of your summer months versus sort of the average of the 37% for the year?
Well, I think the summer is not on the larger percentage, but the April, October piece is what we're considering the summer. So maybe 40%, 45%. Okay. That's helpful.
That's it
for me, guys. Thank you.
Thank you.
This concludes our question and answer session. I would like to turn the conference back over to Dan Dinges for any closing remarks. Please go ahead.
Thank you, Anita. I appreciate the interest from all of our either new shareholders or long term shareholders. As I previously mentioned, this is an inflection point for Cabot. We continue to generate free cash flow. At the same time, we have a very clear path to doubling our production in the next few years.
So all this is good, and I look forward to our long afternoon visit. Thank you.
The conference has now concluded. Thank you for attending today's presentation.
You may now disconnect.