Thank you, Denise. Good morning and welcome to Southwestern Energy's Fourth Quarter and Year-End 2018 Earnings Call.

Joining me today are Bill Way, President and Chief Executive Officer; Clay Carrell, Chief Operating Officer, Julian Bott, Chief Financial Officer; and Jason Kurtz, Head of Marketing and Transportation. Along with yesterday's press release, we also issued our 10-K, which is available in the Investor Relations section of our website at www.swn.com.

Before we get started, I'd like to point out that many of the comments during this call are forward-looking statements that involve risks and uncertainties affecting outcomes. Many of these are beyond our control and are discussed in more detail in the Risk Factors and the forward-looking statement section of our annual and quarterly filings with the Securities and Exchange Commission.

Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance, and actual results or developments may differ materially. We may also refer to some non-GAAP financial measures, which help facilitate comparisons across periods and with peers.

For any non-GAAP measures we use, a reconciliation to the nearest corresponding GAAP measure can be found in our earnings release available on our website. I'll now turn the call over to Bill Way.

Thank you, Paige. Good morning, everyone, and thank you for joining our fourth quarter and 2018 conference call.

We began 2018 with a clear strategy, plan and the right team in place to reposition SWN as a leading Appalachia Basin liquids and natural gas player. During the year, we focused our talent, investments and commitment to deliver improved shareholder value from our high-return assets and projects.

We strengthened our balance sheet, returned capital to shareholders and reduced costs. We delivered on every front quarter-after-quarter and we've transformed Southwestern Energy concluding in 2018, with the close of the Fayetteville Shale sale and we're moving forward.

I'm very proud of, and want to thank our team for another great quarter and year, achieving all of this, while transitioning out of the foundational asset and doing it safely. Extraordinary focus and high-level performance culminating in meeting or beating nearly every operating and financial performance metric, while generating $1.35 billion in cash flow, $100 million above our 2018 capital investments.

So to my team across the country, well done, I'm proud of you. What else did we get right, and what do we would continue to focus on?

We reduced debt by more than $2 billion. We have continued to reduce costs both G&A and interest costs.

And as we promised early in the year, we implemented annualized cost savings of $155 million. Additional savings were also realized in operating expense and well costs.

We've increased our reserves, excluding the adjustment for Fayetteville, and the liquids content of our reserves has grown to 33% of total proved reserves. Further, we are increasing capital efficiency and margin expansion across the portfolio.

We are laser-focused on delivering the full potential value of our assets and continue to add to the list of numerous accomplishments in this arena, including strategic renegotiations of third-party contracts to improve margins. Our teams are driving technical and operating improvements in the way we drill and complete wells to drive down F&D costs, as well as operational and process improvements, including direct sand sourcing, value of water handling, and flowback optimization.

Let me give you some proof points. First, utilizing our Company-owned rig and SWN people, we just successfully drilled and cased another ultra-long lateral, this one in West Virginia in excess of 18,000 feet.

Second, as promised, our new water project in West Virginia is operational and saving at least $500,000 per well for every well drilled and connected in the future. Third, dramatic improvement in cycle time and frac performance has been achieved, and we are committed to delivering a 25% reduction in well cost per foot in 2019, as indicated in our recent guidance.

And Clay will give you details on that shortly. We enhanced our management team and we have a solid foundation.

We are on a deliberate track to sustain free cash flow generation at current commodity prices. There's a great deal of industry chatter about capital discipline and returns-focused investment.

At Southwestern Energy this is nothing new and it has been a demonstrated part of our culture for the last three years. We have a proven track record of investing in our highest return projects that meet our rigorous return requirements at strip pricing unhedged.

Further, we protect the Company's expected cash flow through our rolling three-year hedging program, while retaining a large portion of the upside should commodity prices or basis improve. We entered 2019 repositioned, re-engineered and re-energized, supported by our strong balance sheet, improved liquidity and our clear transition plan is in place to return to free cash flow neutral position in 2020, replacing the cash flow from the sale of Fayetteville with cash flow from higher-returning assets.

We have an extensive portfolio of high-quality acreage with multiple benches and a deep inventory of high-value investment opportunities, both in natural gas liquids and in natural gas. Supported by our premier drilling and completion teams and Company-owned rigs, we have a unique ability to flex our investments across our assets to maximize returns as commodity prices change around.

The increasing returns and productivity from our existing asset base, resulting from continuous operational and technical efficiencies and sustainable cost-saving improvements, continue to elevate the value of our Appalachia reserve base. This year, like last year, our capital program is fully funded and just like last year, we will adhere to our capital investment guidance, ramping it down, should cash flow or returns on the projects be impacted by changes in commodity prices.

I'd like to briefly talk to you about our Marketing and Transportation strategy. We are a leading gas marketer in the country with firm access to numerous high-value market segments.

More than 30% of our gas sales are tied to the premium Gulf Coast price markets this year and 20% of our gas sales are tied to the Northeast city-gate markets where we have the opportunity to capture elevated pricing from winter-driven demand. Our deep gas marketing experience and capability enable Southwestern to opportunistically select a portfolio of right-sized transportation capacity to meet our growing Appalachia business, which reflects a deliberate, but measured approach to layering in firm transportation capacity over time, allowing us to avoid the pitfalls of significant over-commitment.

Our teams work to optimize any surplus capacity resulting from adjusting our capital investment program to offset demand charges. Looking forward, we recently added new long-haul capacity, but not until 2021, timed when we will require it at a discount to the established rate, further improving our margins and market access.

We have no bottlenecks throughout the midstream value chain supporting flow assurance to our premium markets. In applying the same strategic thinking to our liquids, we have planned ahead for some time anticipating future needs.

We continue expanding our direct marketing of NGLs, and we'll continue to pursue this effort to further improve our NGL realizations. The Company enjoys a healthy 53% of crude value for our C3+ NGL barrel.

We secured sufficient gathering, processing and fractionation near our acreage for future growth with firm ethane capacity in place, along with easy access to multiple propane plus takeaway options, including truck, rail and pipe. Finally, I'd like to share a few highlights derived from Southwestern's commitment to environmental stewardship, which places us as an industry leader for best practices in reduced methane emissions, fresh water use and site reclamation.

The 2018 methane loss rate on our current assets was at a record low 0.057, meaning almost zero. To put that into perspective, this is 28x lower than the national industry average of 1.62.

In addition, we maintained freshwater neutrality for the third consecutive year, meaning for every gallon of fresh water we use in our operations, we offset or replenish that gallon of freshwater within the basin. We exercise great care to leave the landscape the way we found it in the communities where we work and live.

We recently earned top honors from the West Virginia Department of Environmental Protection for outstanding work reclaiming our sites and we are grateful for this recognition for our West Virginia team. So as you can clearly see, it's a great time to invest in Southwestern Energy.

We're now the third largest NGL producer in Appalachia, with one of the best balance sheets, no major infrastructure issues, becoming one of the basin leaders in 2019 and capital efficiency as measured by dollars per CLAT and the commitments we've already previously disclosed, and generating real returns on our investments with an energized team that's proven it can execute. Let me turn the call over to Clay for further comments.

Thank you, Bill. Operationally, we capped off an outstanding year with another good quarter in Q4.

We achieved high-end technical, operational and production performance throughout the year, and have carried that momentum into 2019. Additionally, we continued to elevate our strong safety and environmental culture and set Company records in all our key safety performance metrics for the year.

Total production for the year was 946 Bcfe, up 5% compared to 2017, even without the production contribution from Fayetteville for the last 29 days of December. Our Appalachia production was 702 Bcfe, which was a 21% increase versus 2017 and included records liquid production of 63,300 barrels per day, which was 20% of the Company's total Appalachia production.

Liquids production increased 40% year-over-year and consisted of approximately 54,000 barrels a day of NGLs and 9,300 barrels a day of condensate. As a result of a high-quality gas and gas liquids inventory in our Appalachia portfolio, we grew production in both our dry gas and liquids-rich areas in 2018.

That optionality allows us to allocate capital to the highest return projects in both areas and further optimize our capital allocation based on commodity prices at the time. Throughout the year, we continue to enhance our operational efficiencies, execution capabilities, and well performance.

We increased our drilled footage per day, our completion stages per day and reduced our facility installation cycle times. All of these items reduced cost and allowed us to get more activities done, while investing with our - within our original capital guidance.

We drilled three laterals over 15,000 foot each, one being a Company record of over 16,200 feet, and all three of these wells were on-time and on-budget. We will continue to test ultra-long laterals in 2019, and we successfully drilled and cased an 18,000 foot lateral in West Virginia in February of this year.

As discussed in our previously announced guidance, we expect average lateral links to increase from approximately 7,500 foot in 2018 to greater than 10,000 foot on wells to sales in 2019. We were able to improve new well performance through ongoing completion optimization and deliver base production enhancements through gathering capacity expansions and artificial lift optimization.

We also successfully brought online our two water projects. In Pennsylvania and the Tioga area, we will reduce well costs by at least $400,000 a well.

And in West Virginia, we now expect well cost reductions from $500,000 per well to as much as $700,000 per well. We are fully benefiting from these cost reductions with the start of the New Year.

As disclosed in our 2019 guidance, we plan to reduce well costs per lateral foot by 25% this year to approximately $875 per lateral foot. The drivers of this cost improvement are 35% longer lateral links and savings associated with optimized completion designs, a 100% direct source sand, piped water, and vertical integration associated with our Company-owned rigs and frac fleet.

In 2019, we will drill essentially the same number of wells compared to 2018, but with 31% more drilled footage and complete nine fewer wells than in 2018, but with 25% more completed footage for 25% less capital per lateral foot. So we are continuing to prove - improve our efficiencies, get more done with less, and improve economics.

Consistent with last year, we will focus the majority of our capital investment in the super-rich area of our Southwest Appalachia acreage and spend approximately $585 million. We expect to grow the full-year average liquids production 19% with NGLs growing to over 63,000 barrels per day and condensate to over 12,000 barrels per day for a total liquids production rate of greater than 75,000 barrels a day.

We expect Northeast Appalachia dry gas production to be flat year-over-year with a D&C maintenance capital investment level of approximately $300 million. As we mentioned in guidance, drilling and completions activities will be weighted towards the first half of the year and we will average approximately six rigs and four frac crews in the first quarter of '19.

With the sale of Fayetteville, our year-end 2018 proved reserves were 11.9 Tcfe with a pre-tax PV-10 value of $6.5 billion, which benefited from the higher value associated with liquids pricing. Liquids accounted for 33% of the proved reserves, up 25% from last year and 7% in 2016.

In just three years, we have become a meaningful liquids player in Appalachia, which is clearly reflected in the growing value of our proved reserves. Our Appalachia proved reserves grew 7% and the pre-tax PV-10 value grew 72%.

The capital efficiency of our 2018, drilling and completion program as measured by proved developed F&D cost, improved to $0.70 an Mcfe and our reserve-life index was 17 years, excluding all production from the Fayetteville Shale. We continue to progress our inventory of future drilling locations and resources.

At year-end 2018, we have greater than 50 Tcfe of resource and approximately 5,000 future drilling locations across our 482,000 acre position in Appalachia, and all of these are dependent upon commodity prices. We have updated the inventory for longer laterals and for the Upper Marcellus and Utica potential across Northeast Appalachia.

In the Upper Devonian in West Virginia, we brought two more wells online in the fourth quarter and both had initial production rates in line with expectations with liquids production percentages of 49%. We plan to further delineate the Upper Devonian in '19.

The Upper Marcellus has continued to gain momentum in Pennsylvania, as both SWN and offset operators have been tested in this interval. We are continuing to test the Upper Marcellus in 2019, as well as monitoring offset drilling activity.

We have an ongoing effort to convert our existing inventory resources to proved reserves. We are actively incorporating all of the subsurface and completion advancements we are realizing, coupled with operational execution and efficiency improvements to improve the economics of existing inventory wells.

The combination of lower cost and improved production profiles and EURs can move currently uneconomic wells to economic without a change in commodity prices. So as we move into 2019, we have strong operational momentum and are focused on continuing to achieve high-end technical, commercial, and operating outcomes to continue to improve the value of the Company.

And now, I'll turn the call over to Julian for financial highlights.

Thank you, Clay, and good morning to everyone. As both Bill and Clay have mentioned, 2018 was a pivotal year marking record-high liquids revenue and production, successful deleveraging of our balance sheet and a deliberate plan to transition back to free cash flow, following the acceleration and monetization of approximately one-third of our EBITDA with the Fayetteville Shale.

We were cash flow positive by over $100 million as our net cash flow of $1.35 billion exceeded capital expenditures of $1.25 billion, the latter of which was set in the original capital investment guidance and firmly held to throughout the year. Both figures only include Fayetteville contributions for 11 months of the year.

We closed on the Fayetteville sale on December the 3rd, and received net proceeds of $1.65 billion, which reflects preliminary purchase price adjustments of $215 million, primarily related to net cash flows from the July 1st effective date to the December closing date. Over the course of the year, we repaid $2.1 billion in debt; $900 million in the first quarter using cash-on-hand, while refinancing our bank facilities; $900 million through a debt tender completed in the fourth quarter; and the balance on our bank revolver.

Notably, we now have just $265 million in bond maturities before 2025. Our resulting year-end debt-to-EBITDA leverage ratio was less than 2x and our credit ratings remain at BB Ba2.

We have largely completed our authorized stock repurchase program, having bought a total of 44 million shares at an average price of $4.53 per share. As previously discussed, we intend to use a portion of the remaining sales proceeds towards transitioning back to free cash flow through further development of our inventory with a focus on the highest value locations.

The Company has ample financial flexibility with approximately $200 million of cash on our balance sheet at year-end and no borrowings under our $2 billion revolving credit facility. We remained committed to our disciplined capital allocation strategy and have a fully funded capital program in 2019.

For the fourth quarter, we reported G&A of $0.18 per Mcfe, which excludes certain restructuring charges. As previously announced, we undertook a major cost-cutting initiative reducing future annual costs by over $155 million, approximately $75 million from G&A and $80 million from interest.

We recognized total restructuring charges of $39 million, of which $33 million was related to severance costs. Additionally, the non-personnel G&A savings of $20 million will be fully realized this year.

The aggregate of these reductions are reflected in our 2019 G&A guidance range of $0.19 per Mcfe to $0.23 per Mcfe. You'll notice there was no increase in our per unit G&A guidance, despite losing approximately one-quarter of our production volumes from the Fayetteville monetization.

While NYMEX gas prices were essentially flat compared to 2017, our natural gas liquids raised our realized price to $2.57 per Mcfe, $0.28 higher than the prior year. Our realized prices include basis differentials, plus transportation and include the impact of hedges.

For the fourth quarter, when there was short-term price spikes in gas and the NGL markets, the impact of settled gas derivatives reduced our realized price by $0.43. We believe in hedging and are committed to our policy of protecting cash flow with a three-year dynamic hedging program.

As shown in the schedule in our earnings release, approximately 70% of our 2019 gas production is hedged using a combination of swaps and collars to provide pricing floors, whilst providing approximately 65% ongoing exposure to price upside. In 2018, we reported total year gas differentials, which includes transportation, of $0.64 better than our guidance of $0.70 to $0.80.

Gas basis in Appalachia improved even more than anticipated, driven by a wave of long-awaited new takeaway going into service. As Bill mentioned earlier, we have a deliberate approach to layer in pipeline capacity so that we keep our costs low, while planning for access to premium markets.

In 2019, we have new capacity in West Virginia coming into service. This key project increases Gulf Coast access to over 50% on our Southwest Appalachia volumes, and at the same time improving in-basin differentials for the 70% of our Northeast Appalachia gas volumes that are sold in the Greater Appalachia base.

The F&D cost for any excess capacity, which will be filled prior to layering on the new capacity Bill referenced, is included in our 2019 differential guidance of $0.70 to $0.80. We have an experienced marketing team with a strategy to mitigate a portion of any excess capacity and we will provide updates as the year progresses.

As we've consistently indicated, our debt-to-EBITDA target is a sustainable 2x. We intend to transition back to free cash flow over the next two years and believe it is achievable in the current pricing environment by focusing investment in our liquids-rich inventory to replace Fayetteville EBITDA.

We will continue to consider market conditions as we allocate capital, and as we have clearly demonstrated, we'll remain flexible so as to maximize return on investment. This focus has been reinforced with a return on average capital employed or ROACE metric being added to the Company's 2019 compensation program, replacing cash flow per debt-adjusted share.

We believe we offer an attractive long-term value proposition that is not currently recognized in our share price. We believe improved liquidity, favorable leverage, strong cash flow protected by hedges, ongoing lowering of costs and continued efficient operational execution, will reward our investors.

That concludes our prepared remarks. So Denise, could you begin the Q&A session?

Yes, good morning. Bill, I was wondering if you could provide us a roadmap in terms of timing using the current strip where you expect to get to that free cash flow inflection point, and as well as discussing some of the benefits of the sale of Fayetteville on a go-forward basis?

Yes. Thank you for your question.

Good morning. As we look out forward, following the sale of Fayetteville and I'll start with the benefits of selling the Fayetteville.

This was an asset that this company founded and then brought into service and grew dramatically. But as we made a move into the Appalachia Basin with much higher economics and in keeping true to our capital allocation strategy, it became very clear that our Appalachia opportunities, the economics of those would far exceed those that we were able to invest in, in Fayetteville.

And so in keeping with that, we first shifted investment away from Fayetteville, and then the question remains, if you have a large asset and you can monetize that asset and bring those cash flows and EBITDA forward, it makes a lot of sense to do that, all the while growing your investment base and your value creation in Appalachia. So, we monetize that asset as you all know, brought the cash flow in, and major benefit and a major objective was to pay down debt, which we did.

And second objective was to return money to shareholders, which we did. And then the third put us on a transition path by taking a portion of those cash flows and investing them in higher value, higher return projects, thereby growing our liquids, growing our margins and growing our returns for the whole company.

And that very clear deliberate strategy was fully carried out in 2018. And now, as we look forward on this transition path to free cash flow, we moderated capital from our original guidance to reflect conditions in the market, but have now a fully funded program that we will take forward, again replacing cash flow generated from Fayetteville with higher value, higher return projects, and then resulting cash flow going forward.

We believe at mid-cycle pricing, that we are on a very clear path to return to cash flow neutral by the end of 2020

Got it. And just a follow-up.

In the 10-K, on after-tax basis, what's interesting is the PV-10 did increase cost from $5.6 billion despite selling Fayetteville. I was wondering if you can maybe try to highlight to us, Clay mentioned 72% increase I think in Appalachia, but just the - the changes in the PV-10 value from the drill-bit versus, call it the sugar high from higher prices, but just trying to isolate from the drill-bit the change in value called at Appalachia.

Yes, we definitely had some benefit with drill-bit improved-type curves. The biggest driver is the continued growth in our liquids and then benefiting from the liquids pricing that are part of the SEC year-end prices.

So that's where the big Appalachia value growth came from - from a $3.8 billion number to now $6.5 billion.

And I think the Company is repositioning of the portfolio to the Appalachia Basin. Yes, you get the [indiscernible] for higher prices, but you've got to put yourself in a position to capture them before you can just get them.

And so this repositioning of the Company and driving reserve growth in this high-liquid content opportunity is a major driver of that.

Thanks.

Good morning, Bill to you and your whole team there.

Good morning.

I was hoping that - I'm going to take a flier on this. I was hoping that you guys could give a little bit more detail on those two Upper Devonian wells.

I'm suspecting that you didn't give us rates, because - in the press release or in your prepared comments, because you don't want to. But is there anything you can add about - you said they are in line with expectations, but could you give us an idea what the overall Boe rate was from those wells?

Sure, I'll take that. This is Clay.

The reason we didn't include them in the press release is, it's just really early. The wells are performing well.

The 30-day equivalent production rates are from all - both of those wells are over 12 million a day on a 30-day average, in line with offset producers and we're getting the liquids content that we were hoping for. But as I said in the beginning, that early stages, we brought those wells online, part of a five-well test.

We're doing a lot of science to understand all the moving parts and the interaction, so that we can incorporate that into where we go next.

Okay. Thank you, Clay.

Let me just underscore one thing, just so you understand our approach and this is nothing new. Our behavior is exactly the same as it's been for last several years.

When we get into these new areas and we get a well result or whatever, we are extremely careful to put - to not put out a well result that somebody could derive unclear information from, or we don't have the facts yet. We now have three wells in a very large area of Upper Devonian.

We want to bring you along as quickly as we can, but we want to be sure that any of these well results are just well results, they don't have major implications yet, because we just need more time.

Thank you, Bill. I - still the - for a 50% liquids well, that's a - that's an attractive rate.

But if I could ask my second question on the buyback, so you guys carved out or kind of allocated after the Fayetteville Shale $200 million to the buyback, and it looks like you're just about there. Can you talk about whether there is any more appetite on the part of the Board or management to continue or increase that buyback program, or are we basically - is it essentially done at this point?

Well, you are correct that we've nearly completed it, and then it'll be wrapped up here very, very shortly. As far as the option of additional repurchasing of shares or any - really any other option of use of capital, those remain on the table all the time.

And we talk about them, we look at the economic merits and the company as a whole in terms of short-term and long-term value creation, and make those decisions as we - as they come to us. We have just completed it and what I can say is, that option and other options that you might understand debt investment, all of those play out on the table and we evaluate them straight up.

Thank you, Bill.

Good morning, gentlemen. My first question is for Jason.

So the TransCanada issued the press release today that Mountaineer XPress is in full service and then Gulf XPress is in partial service. I was interested if you guys have access to your capacity on both pipelines, and if you could provide a couple of comments about the ramp-up profile through the year?

Thanks. This is Jason.

Thank you for the question. Yes, both our contracts did effectively start on March 1st, today.

So we're - we nominated all the gas for today and we're moving our volumes around in the basin from multiple processing facilities to be able to try to move as much gas into GXT as possible and then down to the higher value markets in the Gulf. With that piece of capacity, we always have the optionality to be able to sell in-basin or in the Gulf and it also connects directly to two of our processing facilities, as well as on a long-term basis.

When we think about MXP, it's strategically located right down through the - through the middle of our acreage. So we have the ability to - you know further development in the future, connect dry gas gathering systems directly into MXP.

So it's a strategic piece of pipe for us and it will take a little bit of time to get our volumes up to where we were at max capacity into the future.

Thanks. This is really helpful.

My second question I guess, is to Clay, about F&D costs. I was just thinking is that - now that the Fayetteville is divested, shouldn't F&D costs decline, call it, from $0.70 per Mcfe, a three-year average to around $0.40 per Mcfe to $0.50 per Mcfe range in 2019?

So the numbers that I talked about in my script, the PD F&D relate to the PUD conversions and the PDP adds that are part of our drilling program. We haven't had much activity in Fayetteville over the last couple of years to where they haven't been in the mix year-over-year on that PD F&D calculation, and we've seen continued improvement there.

The other piece is, like we've been talking about benefiting from the high liquids in our super-rich inventory. When you think about value that's the right way for us to go, but those super-rich wells have less Mcfes.

So when you do the math on an F&D, value is nowhere in that calculation, and so those super-rich wells might get a little bit short-changed in that conversation, but they are the most valuable wells we have in our inventory.

And we prioritize all of our capital program around the value contribution to the company. And so that's why they are at the top of pile.

May I just confirm, I just want to make sure that the liquids rich wells have high F&D cost than let's say dry gas wells, right?

Most definitely. For the reason that I commented on, there's less Mcfe than a dry gas well, you have more liquids and the liquids drive greater value.

Okay. That's exceptionally helpful.

And I guess, I'll just - my last question, if I may, operating cost similar like you commented on F&D cost for liquids rich wells. My understanding is that to say it they'll had lower operating cost structure, is that right?

Yes, it was a little lower in the overall mix of the production, but as we've grown volumes in Southwest app year-over-year with the greater liquids, then we've seen a little - the corresponding increase on the Southwest Appalachia LOE unit cost.

Okay. Got it.

A lot of that elevation in the Southwest Appalachia LOE or it being a little bit higher is tied to the processing costs tied to all the liquids growth.

Thank you so much gentleman. That was very helpful.

Thanks for taking my questions.

Thank you.

Good morning, gentlemen, Paige. Maybe just a first up, Bill, you mentioned in your prepared comments that you're working through some strategic contract renegotiations.

Is there any color that you could provide here just in terms of potential cost savings?

Well, I think when we're done we'll let you know certainly, but we've managed to get this long haul transport at a discount to posted rates. We are always looking at our, our gathering and processing and medium haul providers and looking at how to best expand the value pi so that we can get a better value out of that along with any other costs or any other contracted related items.

So there's no stone left unturned.

Okay. So this is sort of both midstream and services?

Exactly.

Okay, great. And then maybe for my next question, just wondering how you guys are looking at and thinking through just the 2020 hedge book with the curve in such backwardation right now?

Yes. Holly, this is Julian.

Again, committed to the hedging program want to protect the cash flow. Don't particularly like a backwardated curve.

So we've been leaning more on collars where we at least preserve some level of upside exposure. Taking a little lower floor, but getting a write up on the upside in the outer years.

Got it. Thank you, guys.

Good morning. Going back to the Upper Devonian wells, so just kind of a couple quick interrelated questions there.

First of all, when I look at Europe acreage map, does the Upper Devonian occur primarily in the super rich gas area? The rich gas or both?

We believe both. We've tested it so far only in the rich and that will be part of our testing plan to go test it further north in the super rich.

Okay. So that five well test that you have alluded to today was in the rich gas area.

Correct. It was in Wetzel County.

And I was going to ask, I think you just answered it, but just might ask you again, I was going to ask what area, which standard you're going to test the Upper Devonian in 2019 and you're saying you're going to get up and do some tests in the super rich.

Correct. We're going to try to be thoughtful and comprehensive around the delineation and so quality info in the rich and then also in the super rich.

Okay. And I wanted to just ask, hopefully not real long answer, a higher level question.

I was just wondering, are there any specific drilling or completion hurdles that you've had to conquer in order to drill these ever longer ultra-long laterals that were - that are starting to show up every quarter. I mean, closing in on 20,000 feet and it seems pretty long.

So just wondered what have you had to overcome, if anything to get to this point?

Yes. They're definitely challenging.

I think we start off in a unique position with us owning the high quality rigs that we have that are enabling us that they have all the specifications that you need to go to these ultra-long laterals. And I think that's a big part of why we have stayed on track, on our costs and on our timing as we've continued to progress those lateral lengths.

I'll say a facilitating comment to wrap it up is the pace of learning and applying learning that is going on in the company right now with our drilling and completion teams being in source, and the ability to test and move and in a very deliberate fashion is the real enabling factor here. And we have the privilege of being able to do this in two different states in the same region and therefore we can learn faster and faster.

So it's been very good.

I'll just add, I think that's a really interesting point because, as I'm sure you're aware of sometimes people criticize E&P companies for keeping this kind of equipment, tying up capital in it, but what you're saying is, is that you didn't have it. You wouldn't be able to get these kinds of results.

Just saying our teams are doing a great job.

Great. Okay.

Thank you very much. Appreciate the color.

Yes. A couple of questions on well cost CapEx, you're walking down the well cost impressively year-over-year.

Would you expect that to trend down through the year or are you already basically at the targeted well costs?

No. It will trend down quarter-by-quarter, and that will be tied to the big part of that will be the lateral length progression, et cetera.

But it will trend.

Where is your starting point I guess? Where you're current costs?

Yes. So our starting point is around $1,100 a foot kind of combined for the company with all costs included science, et cetera.

And then we talked about the four big categories that are driving this reduction and that is the direct sourcing of sand, which is already contracted. And we're moving forward with that and getting the benefit there.

The water projects and the vertical integration, both of those online benefiting from those, the greater lateral lengths, we were making a significant step going forward in 2019 and a lateral lengths versus where we've been. That's a big driver in that.

We did all the upfront work to enable the wells to be longer. And then the other part is the learnings from our frac designs and our completion optimization.

And so really it's all in place for us and then we got to go execute.

So what would you expect first quarter costs to be per foot, $1,100?

We're going to be making progress, but it will trend throughout the year to have to average that 875.

So you end the year significantly below that level?

The range on that, I mean it's going to be dependent upon the mix of wells and as we progressed through the year, but progress will be showing up every quarter to get to that 875 average.

We have all the building blocks necessary, understood, contracted and ready to execute.

Well, I guess if it averages 875 through the year, could I assume a lower cost than that in 2020? Average is that it would end lower if it starts higher…?

Yes. Again that that is impacted my lateral lengths and everything else to where we are.

We haven't guided to the 2020 or thought that far ahead yet around what that range is going to do, but we expect to continue to maintain the execution improvements and efficiencies that we're getting.

Okay. And you talked about the wells being the CapEx being first half weighted?

Could you give us a percentage of CapEx by quarter as we go through the year?

Well, you'll see is a pattern similar to what we did last year. We'll begin with 6-rigs in the field and then feather of that back to remain within cash or within the capital budget.

And then we'll adjust that accordingly as we should see a big departure on commodity prices. So if you just kind of look back at that they're not too the similar in terms of pattern.

Okay. Thank you.

You Bet.

Good morning, guys. Just a couple of miscellaneous questions.

Any other non-core assets that could be out there - that could be monetized to further the balance sheet discussion, you're building in Houston comes to mind for one or is there anything else along those lines that could help? And then the second question is C3+ 53% a good number, but some of the other benchmark numbers that I've seen on a C3+ from your peers 60%?

Is that kind of achievable number over the course of the next 12 months to 24 months as you maybe bring some more of these functions in house? Thanks.

Sure. In terms of the asset base, you'll recall that we went through and did a lot of that cleanup in the last couple of years.

So we don't have assets that are targeted for sales this point. And again, our portfolio has been very well cleaned up.

Your question on the building, we are already in one of our two buildings, so we will be moving out of the - disposing of the other tower that's, we're well ahead of that. In fact the whole team is just in one side of that.

And your other question had to do with…

C3+

Our transportation is in our - are realized price. So I need every day I'd have to just get a better understanding of who else does that or doesn't do that.

That's always been a, an issue that we see my check to see if that benchmark number you have has got transportation and it or not.

Okay, good. Thanks.

And then from a strategic standpoint direction of the assets that we have on hand. Sounds good.

I mean, how would you think about, if you were to lay out at three year strategic plan not numbers, but just kind of broadly speaking, what would you like to accomplish in the next three years? In high kind of 30,000 foot kind of a concept standpoint.

If you could kind of lay that out that'd be great.

Yes, I'll tell you that anything that looks like, specific A&D opportunities or any of the things like that we don't really comment on as we work. So in any company that you're looking at strategic opportunities for you to look at opportunities and you focus on the highest value creating ones and those sometimes come your way or sometimes you figured them out.

But at least focus us back to now and the going forward part of what we already have, we're always thinking about ideas on the way to improve the short-term and long-term value creation of our assets and drive shareholder value. So we've got really a multifaceted approach to this.

We've got - we're building greater and greater share of our cash flow derived from gas liquids. We believe that is a value creator and we've demonstrated that we can do that.

We're expanding margins and returns in every piece of the business, benchmarked against our peers and taking action as we need to improve those. Our resource to reserves work we've grown our resource in the company this last year.

The objective is from an organic perspective, drive those resources to prove reserves, to build our deep and deepen our inventory and grow for that inventory. A lot of focus on Upper Devonian, a lot of focus and Upper Marcellus and then building out our greater understanding of Utica across our entire portfolio in the Appalachia Basin.

We continuously look at refining our structural costs, your question around buildings and different structural costs like that. If we don't need it doesn't add value, then we've got to move it on.

We leverage our ability to flex with pricing, so we have it gives us more opportunities for bolt-on acreage or any other kind of thing that we can do that drives our agenda of improving efficiency, including longer laterals that kind of thing. We have a clear path to longer laterals.

We have a clear path to reducing costs. We have a clear path to expanding our share of liquids to our total margin than total revenues.

And as always, again, as opportunities or ideas come to us and we'll evaluate them with the clarity and rigor and discipline that we are known for in our business and we'll make decisions around those and make decisions around the - capturing the benefit of those as we can assure that they will happen. And so that is our track going forward.

That answer had a lot of passion behind it. Love it.

Thank you.

Good morning.

Good morning.

With the Fayetteville sale, of course, it changes the portfolio so much that some of the things you talk about have made me wonder about other issues. As far as the rich gas inventory versus the dry gas inventory, you were talking about the - if you just looking it on a Mcfe basis, it'll be kind of misleading as far as the relative unit F&D costs.

But I was thinking where we are with this commodity pricing? How you drill out the inventory in your plant?

Does it change a lot between say 275 or 250 dry gas and 325 dry gas, again, given the overall different costs mix that you have now?

Yes, one of the great things about the portfolio that we've put together and that we're focused on is that we have so much flexibility to deal with the three major components, commodity pricing, differentials and commodity pricing being liquids or gas and then the differentials that impact that. And so as you look at how we develop our business going forward, and again because of the fact that we can control how agile we can be, where we can shift money to from a physical perspective.

If gas prices shot up and liquids prices dwindled, we could switch to our high value, high volume gas wells that are on an equivalent basis about the same in value today. And so you finish up well series in West Virginia and move over to Pennsylvania and continue on or vice versa.

Today and through the next period, we view the liquids - the strength of the liquids relative to gas such that we invest on the six well program, our four rigs in the West Virginia, two rigs in Pennsylvania, we can easily switch that back. Another big piece to this whole thing is if pricing goes down to where our required returns on these wells or just the sheer fact of investing in capital doesn't meet the rigor and discipline that we set out.

We will just simply slow down or stop. And we have done that before.

We did it in 2016 when pricing collapse. We stopped all drilling and completions across the whole company.

Six months later, prices we're back and we resumed. And so we don't do that every other day when strip moves around.

But you understand, as we look at those trends against strip, we make those informed decisions and as you look at the total cash flow we generate and the total cash flow consumed in decisions around capital, we flex with those prices. So it's a very dynamic, we're very agile and I think our portfolio is a big piece of that.

Great. And I wanted to ask about the 18,000 foot plus lateral you had in West Virginia.

Some of your peers have struggled quite a bit with pushing out lateral length, and I realized that your approach has been to be pretty incremental in how you do them. I was just wondering - if you said you got it done successfully, I just wondered if it was pretty much a straightforward process, did you have any challenges anything that you're going to watch forward or that you'll try to tweak the next time you're drilling out that long.

Yes. Let me start with - we purpose built and designed the seven rigs that we own to be able to drill extended length laterals anywhere we chose to drill them.

So our people help build them or helps back them and then we had them in purpose built. We began this process on much shorter laterals.

I mean, we were at a place at one point in our time that we were averaging 7,500 feet as we entered into the business and then saw the opportunity to drill longer laterals. And so we do a couple of different things.

We learn from others. We rigorously absorb what we hear in the industry.

We take a well plan with a very integrated team and we drill that well on paper, on the tabletop, and we look for a pinch points, challenges, issues, and mitigants to deal with that. So if you're looking at a torque and drag budget or torque and drag as an issue, we create a - what we call a torque and drag budget to be able to work that.

And we have guidelines. We model it and we know when we're up against an issue and if we haven't solved it, we just don't go far, go longer.

So as we've worked through all of the technical issues well by, well again two different places, so we can see how it works into a total dry gas and total wet gas. We can see that we can advance that.

We learn and then we extend a little further. We don't extend just for the sake of extending.

If we can't convince ourselves that that we have the risk managed, we simply will not drill longer laterals. And you can see as we walked up to 18,000 feet and successfully case that well that we understood the risk, we manage those risks and between the equipment, our people expect and our people's capabilities they delivered.

I think if you get into a place where you're just reaching for the longest lateral, you can possibly get and you do it all at once, there are pitfalls and, we just believed this one is more of an incremental approach.

And just to clarify, on this what you talked about the budgeting, did you sort of meet the AFE, you would originally set out and going forward, would we expect similar wells to be about the same cost or do you think you'd be - those would be driving down just need for less science and so forth.

So proudly on time, on budget, against fee, and that's rigorously managed as well. And then as we said in the beginning of this whole thing, as we move forward in time, our portfolio of wells, we drill up, costs will go down and these individual laterals, we'll get more and more, and more efficient and we will bring the cost down on those as well.

Great. Thanks a lot.

You bet.

Hi, good morning and thanks for fitting me in.

Hi, Sean.

Bill or Clay, on NGL marketing, could you guys remind me how much of the volumes that you are currently marketing yourselves versus third party and then it sounded like the plan is still to kind of ramp up your own kind of internal marketing efforts there. Could you talked about that scaling up process?

Sean, this is Jason. I'll take that question.

So what we've done is we've hired some experienced and experienced team members and recently put them in place and we're going to use the same logic that we have with gas. We're going to try to maximize the barrel, the value of our NGL barrel through building strategic NGL sales and a takeaway portfolio where we create flexibility and optionality to access multiple markets while we're trying to minimize our long-term FT commitments.

And we're looking for, rail, hype access and truck access as well. And what we've done, we've entered into several agreements that were at our processing facilities to where at one facility were taken about a third of our propane volumes in time.

And at the other facility, we're taking 100% of them in time. Right now we're working directly with the agents to lock those sales up directly with end use markets.

So we have the ability to direct where they go when the sales price on those barrels.

Okay. That's helpful.

And then I guess from the longer-term perspective on that, could you talk about, how you think about that marketing strategy as stuff like new Marcus Hook in some of the other demand, projects get built in basin, how that may cause you kind of reposition the marketing for NGLs?

So I think we're in a unique position right now because we haven't made a lot of long-term contracts or commitments and we're starting to ramp up that business and all of our frac facilities, they have the ability to connect to the grid up there in that area. So we do have access into Mariner East and the ability to get over to Marcus Hook as well as the ability to sell into rail and then trucks, trucks in the winter.

So we're strategically in the process right now of trying to set that portfolio up of such that we create as much value moving forward as possible.

Got it. That's helpful.

And then just lastly Bill or Julian, I know you guys mentioned that you want to return to free cash flow neutrality end of 2020. Can you just talk about kind of the more strategic picture there?

Is the goal just to achieve neutrality or has there been any change in your view or thoughts around more of a formulaic return of capital as you go forward?

Yes. I don't think we've changed at all.

We're continuing down the path of wanting to get to free cash flow, because we think that's the right way to run the business. We want to get to that sustained 2x leverage and so that's another sort of parameter that you put into the mix.

And so, as we build the plant and as you have different prices, obviously, you move back and forth, you can get to that free cash flow, it may change how long it takes you to get to sustain 2x, but it's very important to us to keep the strength of the balance sheet because that gives us the greatest ability to maximize long-term value. So when it comes to returning capital, that's something that's in the mix, but you wouldn't return capital to the detriment of hitting those two other goals.

Got it. That's very helpful.

Thank you very much.

Thank you and thanks to everybody for being here this morning. I've just got a couple of things to say and that is, first of all, I hope that we've demonstrated in 2018 that we forged ahead on really determined plan to reposition the Company, capture greater value creation for our shareholders and the fact that we delivered on every commitment we made.

And that's a hallmark of how we operate this Company. We are driven by returns-focused investment and defined by demonstrating rigorous financial discipline as we transition the Company back to free cash flow as prudently as possible and certainly within the time table we've laid out following the divestment of Fayetteville.

We are always thinking about ideas and opportunities to go forward and we evaluate those ideas with clarity, rigor and discipline that you've gotten to know us for, but with a keen eye to assuring that there is real long-term value creation and that long-term value creation is deliverable, when we say it can be delivered. We are focused on building our inventory right now from the reserve - the resource, the growing resource we have and converting that to reserves.

We will continue to drive a greater and greater share of our cash flow from high-value gas liquids in the investments we have in Appalachia. But we have the flexibility to shift back and forth and we will do that.

And we have a track record of doing that to make sure that we have - always have a fully funded budget and that fully funded budget is supported by rigorous returns, otherwise we pull it back. Throughout this year and the coming years, we continue to look at every cost, we look at every margin, we look at every revenue and we drive for benchmark top-quartile success, because that's how you win in any business you're in and how you win in the basin.

We believe that we are careful stewards of the investments that our shareholder is making us and we're taking actions every day to create and preserve long-term value. And we want to do all of this with our differentiated capabilities in drilling and completing the vertical integration, but always remembering that all that doesn't matter unless we do it safely and with strong environmental stewardship.

So that concludes our call, I want to thank you for joining us today. We hope you have a great weekend and we look forward to talking about our next quarter's worth of achievements next time we're together.

Thanks a lot.