山脈資源 (RRC) 2016 Q3 法說會逐字稿

Welcome to the Range Resources third quarter of 2016 earnings conference call. Statements contained in this conference call that are not historical facts are forward-looking statements. Such statements are subject to risks and uncertainties which could cause actual results to differ materially from those in the forward-looking statements. After the speaker's remarks there will be a question and answer period. At this time I would like to turn the call over to Mr. Laith Sando, Vice President Investor Relations at Range Resources. Please go ahead, sir.

Thank you operator. Good morning everyone and thank you for joining Range's third-quarter earnings call. The speakers on today's call are Jeff Ventura, Chief Executive Officer; Ray Walker, Chief Operating Officer; and Roger Manny, Chief Financial Officer.

Hopefully you have had a chance to review the press release and updated investor presentation that we posted on our website. We also filed our 10-Q with the SEC yesterday. It's available on our website under the Investors tab, or you can access it using the SEC's EDGAR system. Before we begin let me also point out that we will be referencing certain non-GAAP measures on today's call. Our press release provides reconciliations of these to the most comparable GAAP figures. In addition, we posted supplemental tables on our website to assist in the calculation of these non-GAAP measures and to provide more details on both natural gas and NGL pricing. With that let me turn the call over to Jeff.

Thank you Laith. We are excited that we closed our merger with Memorial on September 16. The integration of the teams and the assets is going very well. Range now is a better, stronger company with strong teams and high-quality assets in both our Marcellus shale division and the new North Louisiana division.

I begin by reviewing what Range accomplished during the quarter, and then I will discuss some of the key attributes we have that I believe set us up for success. Range's ability to consistently drill low-cost, high return wells across our acreage in the Marcellus, as well as focus on driving down unit costs resulted in solid operating results for the third quarter, and due to the closing date, 15 days of solid performance from the North Louisiana team were represented in the quarterly numbers.

The third quarter took us one step closer to seeing meaningful improvements in realized prices across all of our products. First, all three of our liquids projects were online during the quarter: ATEX, Mariner West and Mariner East. We sold ethane to Europe, Canada and to the Gulf Coast, and exported propane for market (inaudible) for international markets. The net effect is that our NGL price increased from 13% of WTI to 25% of WTI on a year-over-year basis.

Second, we have a new condensate sales agreements which commenced on July 1. These agreements improved our corporate condensate realizations from a $13 differential to WTI, to a $6 differential to WTI on a year-over-year basis, in a similar improvement compared to second quarter of this year.

Third, NYMEX gas prices were higher in the third quarter, and all of the gas pipelines we are contracted on are expected to be on schedule. This includes Spectra's Gulf Markets Expansion, which came online earlier this month on October 4. This transportation allows us to move an additional 150 Mmbtu per day of all Marcellus production to the Gulf Coast. Like the Uniontown to Gas City pipeline, which became operational this time last year, this project immediately improves our expected Marcellus netbacks.

The next two projects for Range are Columbia's [Leatrain Xpress] and ETP's Rover Phase 2, both of which have received first final EIS approval, and both of which we understand will be operational in the fourth quarter 2017. As a result of this increased transport in our growing North Louisiana production, we expect to see corporate natural gas differentials improving to approximately $0.46 next quarter, based on current strip pricing, and approximately $0.33 in 2017. All else being equal, these improved netbacks should improve margins substantially in 2017, and we expect further improvements in 2018.

Let me turn to North Louisiana and give an update there. The integration, as I mentioned earlier, is going very well and the North Louisiana division is accomplishing a lot. Let me give a few examples. First, we just set a record for the fastest spud to rig release of any well drilled to date in Terryville Field, and then repeated that record with the second well. In addition, we just completed one of the best producing wells ever drilled in the field to date.

Our purchasing department has also made good progress, and we are achieving cost reductions on the front as a result. Ray will talk more specifically about these accomplishments and improvements in a few minutes. The North Louisiana team has also had some early success refining the targeting and landing in the Lower Cotton Valley. As an example, they just finished drilling some wells that were entirely within a much tighter target within the Upper Red. Once we complete the wells, we will see what effect this has on performance.

It's early, but we're also excited about the North Louisiana extension areas. The team has drilled the pilot holes for the first three extension wells, all testing new areas several miles away from Terryville, and far away from each other. Based on extensive logs, [cores], and shows, all three vertical pilots look very encouraging.

In addition, we have drilled and encased the horizontal laterals on two of the three pilot holes. Again the results to date look encouraging. The third lateral is currently being drilled. We expect to have all three wells drilled, completed, and tested by the end of this year. The results of the wells will help provide additional data regarding extension areas that will be rolled into our planning for 2017 and 2018.

On a macro level, there are signs that later this year, and into 2017, supply and demand will be more balanced and pricing can improve. We expect natural gas production in the US to continue declining for the remainder of the year. Based on available data, it appears 2016 will be the first time that natural gas production will decline on a year-over-year basis since 2005. This supply decline is happening while demand for natural gas is increasing, driven by Mexican exports, power generation, and LNG exports.

Looking towards 2017, the NYMEX strip has moved above $3, and we think it can continue to climb. Based on where strip pricing is today, we believe that we can grow the combined company a 33% to 35% for 2017. This equates to an organic growth rate of 11% to 13% for 2017, coupled with the full year of the North Louisiana division versus roughly a quarter in 2016. Importantly, this preliminary plan for 2017 also results in strong growth for 2018. Assuming a $3.25 per mcf and $60 per barrel, we are projecting that we should achieved organic growth for 2018 of approximately 20%.

We believe that Range's Marcellus and Lower Cotton Valley assets are two of the lowest-cost gas plays in the United States, which results in a resilient and flexible platform for sustained growth. This combination creates a unique portfolio that is strategically located near key demand centers, with more optionality for Range and an enhanced ability to serve our end customers. The product mix in both assets are similar, which enables us to utilize our marketing expertise for both natural gas and NGLs, and leverage our existing customer and transport relationships to find innovative sales arrangements, just as we have done in the past.

In summary, we believe that Range offers investors five key positive attributes. The first is a very high quality, low cost asset base in two very complementary basins. The second is improved capital efficiency, as illustrated by the opportunity to go back onto existing pads to drill new wells in the Marcellus and to drill highly prolific wells in the Lower Cotton Valley. Continuing to drill longer laterals, and optimizing landing and targeting will also drive improved capital efficiency in both regions.

The third key attribute is top-tier operational execution as evidenced by a consistent track record of operational achievements. The fourth is a strong marketing effort, highlighted by Range's ability to sell its products to multiple markets, enhanced by our newly acquired North Louisiana assets and demonstrated in our expected pricing improvements across all products heading into the fourth quarter of 2016 and further into 2017.

Finally, Range has an even stronger balance sheet with ample liquidity and a strong hedge position for the remainder of 2016 and 2017. All of these attributes position Range to deliver strong operating results and build sustainable long-term shareholder value. I will now turn the call over to Ray to discuss our operations.

Thanks Jeff. We continue to execute in the Marcellus, and are already achieving significant wins in North Louisiana. Production for the third quarter came in at 1.51 Bcf equivalent per day and for the fourth quarter we're setting guidance at 1.85 Bcf equivalent per day.

Excluding the asset sales and the North Louisiana volumes, we expect to grow 10% over last year as previously guided, while maintaining our capital expenditure level at approximately $495 million. And importantly, we plan to end 2016 with an exit rate higher than last year, setting us up well for 2017 and beyond.

We continue to make great strides in unit cost reductions, and this is something we are really proud of. Specifically driving this improvement, in the southern Marcellus we have seen a 35% reduction in LOE year-to-date, versus the average for 2015. This was achieved through three key areas. One, leveraging service cost with our long-term vendor relationships; two, reductions in third-party manpower; and three, the savings associated with our water handling through our water logistics team, which gets water from our production pads to our frack operation quicker than ever.

Staying with our Marcellus activity, capital efficiency continues to improve and I will review some examples from our operations in Southwest Pennsylvania. On the water front, we've continued the improvements that we discussed on the last call, and will reduce our capital expenditures for water by over $20 million this year. We have reduced the total average completion cost per foot of lateral by 20% as compared to last year.

Our top three pads completed in 2016 have averaged over 8.5 stages a day, for a total of 432 stages. The best pad achieved a completion cost per foot of almost 23% below the average, which again was already 20% lower than last year. We're forecasting a 16% reduction in CapEx for production facilities, resulting in almost $6 million in savings this year as a result of design improvements, reductions in labor and material, and redeployment of existing equipment.

On the drilling side, we have achieved a 5% reduction in drilling costs per foot compared to last year, and eight of our top 10 best days for lateral feet drilled in a day have been this year. This illustrates that we're still improving and expect to continue to improve going forward. As we've covered many times in the past, we believe our average total well cost per foot including facilities are the best in the southwest portion of the basin.

We believe if you look at some of our recent achievements, which are clearly more than just a few wells, you will begin to appreciate the improving capital efficiency that we expect to see going forward. Again, all of this being done safely and in an environmentally sound manner by a strong operations and technical team, and by all our folks across the Company.

Today we can drill a 9,000 foot lateral and complete it with 45 stages in our wet area with full facilities on a new build, four-well pad for approximately $7.2 million per well. In comparison to our peers, our cost is less. In fact, over $1 million less on an apples-to-apples basis, and our well performance is better, resulting in better economics.

I should point out that this is not just theoretical. We have many of these types of longer lateral wells planned for the future. Like I reported on the last call, we are now drilling a seven-well pad in our super-rich area averaging approximately 10,700-foot laterals with the longest at 14,500 feet. These wells will be completed early next year, and we look forward to sharing the results of these and other long lateral pads in the future.

I would like to take a few minutes to walk you through some of our recent top-performing wells during the third quarter. Before I do that, I want to remind everyone that these rates will all be reported as constrained actual rates to sales. In our dry area, a four-well pad with an average lateral length of 5,300 feet and 28 stages per well was completed, and had an average 24-hour rate to sales of 20 million cubic feet equivalent per day.

In our wet area, two pads showed excellent results. A four-well pad with an average lateral length of 6,800 feet and 35 stages produced at 22 million cubic feet equivalent per day per well, and a six-well pad with an average lateral length of 4,500 feet and 23 stages produced at 19 million [cfe] a day per well.

On the last couple of calls, we have also discussed our unique advantage of the expansive inventory of existing pads and infrastructure which allows us to drill wells at lower cost, thereby increasing capital efficiencies while allowing us to ramp up quicker than any of our peers. Currently we have an inventory of over 230 pads that we could eventually utilize. This is comprised of new pads, pads that are in various stages of execution, 124 producing pads with five or fewer wells, and 59 producing pads with six to nine wells. All of these represent opportunities to drill more laterals at very attractive costs.

Although it is early in the planning process, in Southwest Pennsylvania our current plans have us drilling about one-third of our wells on existing pads in 2017. That number could increase to as much as half of our wells in 2018. Our average drilled lateral length in 2017 is planned to be over 8,000 feet, and our expectation is that the 2018 average lateral length will be longer.

Again, these are early estimates and will most certainly change over time. What is important is that we have the ability to drill longer laterals, drill on existing pads, and we have permits in hand with infrastructure in place to yield further improving capital efficiencies going forward.

Shifting now to North Louisiana, the integration is going very well. We will be operating those assets out of our new North Louisiana division office in Houston under the direction of John Applegath, Senior Vice President of the new North Louisiana division, who has relocated there to Houston from our Southern Marcellus division office in Pittsburgh. Dennis Degner, now Vice President of the Southern Marcellus division steps up to take over the Southern Marcellus Shale division. We are extremely proud of both of these gentlemen and their accomplishments. Their record is clear and through their leadership we expect continued improvements in capital efficiency coupled with improving well performance in both areas.

When we originally evaluated the Memorial assets, our expectations were that we could improve on the already impressive results they have seen there. For example, we thought there was potential in terms of drilling times and costs, coupled with improvements in well performance by optimizing the target window and staying in zone, all of which should result in improved efficiencies and productivity over time.

Even though we've only had the reins for approximately six weeks, as Jeff referred to in his remarks, John and the new team our already achieving some significant wins. We just set the record for spud to rig release in Terryville of 30 days and have now repeated it on a second well. To date this year, for wells averaging more than 5,000 feet of lateral length, the average has been 40 days. This 25% improvement in efficiency was achieved by implementing more aggressive bits and high-speed, high-differential motors.

A lot of these ideas and many more coming are the result of us bringing and Scott Chesebro as our new Vice President of Drilling. Scott has a ton of experience in high-pressure, high-temperature drilling across the world, and was actually involved in the vertical drilling in the Vernon Field. We expect Scott and his new team will be able to significantly improve drilling performance and costs as we go forward.

In the last batch of wells that were completed we also saw one of the highest productive wells in Terryville to date. It had a 30-day IP to sales of 437 million cubic feet of equivalent per day per 1,000 foot or, over 27 million cubic feet equivalent per day, which is 68% higher than the average. We believe this is a real testament to both the team and the quality of the rock in Terryville, and clearly illustrates that there is more potential yet to be unlocked as we further develop the Upper Red along with the stacked pay opportunities in the Terryville Field. Like I've said many times over the years in the Marcellus, I do not believe we have drilled our best well yet in Terryville.

We've also had a quick win on targeting. When drilling into the Upper Red prior to Range, the target for the lateral ranged from 100 to 125 feet thick, encompassing most of the reservoir. We believe there may be significant performance improvements by incorporating an approach where we target only the best [across] the interval, which is 20 to 40 feet thick, and then stay in that much smaller target window for 100% of the lateral. We've already accomplished this on a few wells and expect to announce those results next year when those wells are completed.

Bringing to bear the supply chain advantages of Range has also resulted in an early win. For example, we've already saved 7% in casing costs, resulting in savings of over $50,000 per well and we expect that there will be many examples of this going forward. As illustrated in these few early examples, we believe strongly that we can lower costs, improve well performance, improve operational efficiencies, and lower our unit costs while working safely and being good stewards of the environment and the communities where we live and work. We will bring to bear our operating philosophy of study and strategic planning, implementing innovative and sound technologies and processes that have worked for us in the Marcellus, while putting in place a long-term approach focused on economic and value-enhancing growth.

Like Jeff mentioned, we're currently working on the three extension area wells. Two of the wells are in the completion phase and the third well is nearing completion of the drilling phase. We expect to be able to have initial results from these three wells before year end.

Looking at the data collected thus far, the Upper Red sands in these wells have an average gas in place concentration, that is Bcf per vertical foot, that is on par with the Upper Red in the very best part of Terryville. And, they are twice as thick, yielding twice the gas in place as the Upper Red sands in Terryville. The Lower Red sands have an average gas in place concentration nearly three times that of the best Lower Red in Terryville. Considering these wells are deeper and have a higher pressure gradient, we interpret the high reservoir pressure, better gas in place, and the favorable reservoir parameters to be cause for optimism regarding these areas in the basin.

Of course, we won't know for sure until we see the actual production from the wells but one of the many things that our technical team has learned, especially after drilling and analyzing the early data from these expansion wells coupled with our analyses of the existing producing fields and the more than 50 vertical tests throughout the acreage, is that the Lower Cotton Valley sands in this portion of the basin are fairly consistent, giving us support for our optimism. Even so, this does not take into account the other two to three horizontal targets available throughout the acreage.

Shifting back to the Terryville Field, both Red zones and both Pink zones have been tested to date, along with further development in the Upper Red which has been the primary target. We will also be looking at the Lower Red and the Deep Pink going forward. We see a lot of value in the stacked pay development, and combined with lower costs are encouraged about the future potential in Terryville, along with the extension areas.

For 2017, [for the year] with approximately 25 drilled and uncompleted well bores in North Louisiana, which we plan to complete in the first quarter. This will result in outsized production growth early next year into what we think will be a stronger pricing environment. As we smooth out the completion activity going forward, I believe we will have a Range-like approach of steady quarter-over-quarter growth in North Louisiana as we enter 2018.

Switching to marketing for a few minutes, in addition to improving netbacks in the updates that Jeff discussed during his remarks, I would like to re-emphasize a couple of points before I close. There have been a lot of questions about pipeline projects in Appalachia. Are they on time and what impacts might they have on basis and so forth?

Remember that Range was the first mover in the basin, and we have been working on a diversified and layered portfolio of transportation for many years. As Jeff discussed, we believe the projects that we are in are on time. We sell to multiple markets and have been consistent in our strategy since we discovered the Marcellus. One pipe does not make a big difference to Range, as we are diversified -- as we have diversified exposure over multiple pipes.

Our 2017 natural gas differential is expected to improve by $0.10 to $0.15 based on current strip pricing. And our pricing is much more resilient having multiple outlets and a large base of North Louisiana production. Again, we just acquired a world-class asset in North Louisiana that gets very close to NMEX pricing and provides marketing and capital flexibility. So now, one pipe makes even less difference.

We set capital budgets at the beginning of every year that capital is allocated on a real-time basis. Having two of the most economic plays in the US is a unique advantage, and we have the flexibility to allocate capital real-time as conditions dictate. None of our peers in Appalachia have this option. As both our Southern Marcellus and North Louisiana divisions continue to improve on cost, efficiencies and performance we expect there will be a lot of value as markets improve. Now I would like to turn the call over to Roger.

Thank you Ray. I'm delighted to report the third quarter of 2016 is the quarter we've been waiting to talk about for a long time. Natural gas, NGL, and oil sales before cash-settled derivatives was $304 million. That is 36% higher than the second quarter of this year. Cash flow at $123 million was 32% higher, EBITDAX at $160 million, was 24 % higher and cash margin at $0.82 was 17% higher.

Range has navigated this period of low commodity prices well, and by all measures the third quarter of 2016 appears to mark a financial turning point for Range. Given that the third quarter includes only 15 days of operating results from the Memorial merger, we are excited that we have not only turned the proverbial corner but are now moving forward on a wider, unique and more prosperous new road.

The reasons for optimism and confidence in Range's path are multifold. We have attractive new optionality when deploying capital, production continues to steadily grow, the cost structure continues to improve, and the higher margin, marketing and transportation arrangements we have spoken of in prior quarters are now fully operational, delivering the improved cash flow and margins we predicted.

Year-to-date cash flow was $360 million and year-to-date EBITDAX was $424 million. Fully diluted cash flow per share in the quarter, which again includes only 15 days of cash flow from the Memorial merger, was $0.68 per share.

Looking closer at the third-quarter cost structure performance, the Range teams have continued to do a terrific job holding the line on cash direct operating expense, which at $0.16 per Mcfe was roughly the same as last quarter, and a 38% improvement from the third quarter of last year. All other unit cost items came in at or favorable to guidance with the exception of interest expense, which was $0.04 over guidance due to nonrecurring transaction expenses associated with the successful senior-subordinated note exchange, which I will further discuss in a moment.

The third quarter DD&A rate was $0.95 per Mcfe, identical to the prior quarter and 18% better than the third quarter of last year. Please reference the third-quarter earnings release for full fourth quarter 2016 unit cost expense guidance.

Moving to the balance sheet, investors will note many positive changes resulting from the Memorial merger. The third quarter debt-to-capitalization ratio improved from 49% at year-end 2015 to 41% at the end of the third quarter. Debt to rolling fourth-quarter EBITDAX, including the Memorial debt and historical four quarters of their EBITDAX, was 3.6 times. The combined Range and Memorial balance (inaudible) limit our debt-to-EBITDAX leverage to the mid-three times range, with the ratio getting better next year as higher cumulative cash flow improves the ratio moving into 2018. By the end of 2018 we expect the debt-to-EBITDAX ratio to have declined at least a full turn from continued growth at or near cash flow.

Our forward-looking recycle ratio remains above the two times level as NYMEX prices have further strengthened, and our marketing contracts in North Louisiana productions allow us to move more of our products at higher margin sales points.

The Memorial merger also provided an excellent opportunity to further advance our balance sheet structure. Pre-merger, Memorial had a partially-funded, fully conforming $1 billion bank credit facility and $600 million in unsecured senior notes outstanding. Pre-merger Range had a $3 billion bank credit facility with only $3 million outstanding against its $2 billion commitment amount. Range also had one issue of unsecured senior notes outstanding, and three series of unsecured subordinated notes. The merger allowed Range to re-simplify the Company's debt structure into a single bank credit facility and a single tier of unsecured senior notes through a comprehensive bond exchange and tender offer.

Here is briefly how it worked. The Memorial bank credit facility was canceled at merger close. The collateral was released, and the outstanding balance was moved to the existing Range bank credit facility. Over 97% of the three series of range subordinated notes were exchanged for like rate and like maturity range senior notes, and the Memorial senior notes were exchanged into like kind Range senior notes or redeemed for cash at the holder's option. With the majority of the Memorial senior note holders choosing to accept Range notes rather than cash.

The exchange was very successful. The Range subordinated notes are now senior notes. The Range and old Memorial senior notes are now all pari-passu Range senior obligations, and share the same covenant package as the Range existing 2025 senior notes. This allows bond investors to trade freely across the entire rate and maturity spectrum without making structural credit adjustments due to price. The exchange allowed Range to utilize some of our low-cost, unused bank commitment while still providing close to $1 billion in committed liquidity.

Following the exchange, all of the Range bonds traded at tighter spreads than before the exchange and both Moody's and S&P move Range to Stable Outlook. While Range is not yet investment grade, the bond exchange aligns our balance sheet closer to what is expected of an investment-grade company. My compliments to the Range finance team for completing this complex and highly successful series of transactions, which makes our balance sheet even easier to understand and positions us well for future growth and credit quality improvement.

The Range hedge position was significantly enhanced by the Memorial merger, with the post merger hedge book holding higher hedge natural gas volumes and prices. Range also added hedge volumes across all of our products during the third quarter. Please reference the earnings release, third-quarter 10-Q and Range website for specific post-merger hedge volume and price information.

In summary, the third quarter showed the fundamental improvements in topline revenue, cash flow and margins [flowing] through the Range financial statements that we have all worked so hard to achieve. With the financial statements reflecting only 15 days of Memorial ownership, and the exciting results Range has discuss in both Appalachia and North Louisiana, we look forward to continued operating and financial progress in the quarters ahead. Jeff, back to you.

Operator, let's open it up for Q&A.

Thank you, Mr. Ventura. The question and answer session will now begin.

(Operator Instructions)

Arun Jayaram, JPMorgan.

My first question is, just your broad thoughts on capital allocation between the Marcellus and Northern Louisiana as you think about 2017 and 2018, I think you are running four rigs in Terryville right now. So how are you thinking about capital allocation?

I also wanted to see if you could comment, I do know that MRD had some under delivery on the Pentex system, so that could provide an outlet for some kind of value-added growth, thinking about the MVCs there.

That's a good question. Again I want to stress, when you look at 2017 we are projecting an organic growth rate of 11% to 13%. That's an output from several different scenarios where we are allocating various percentages of capital between the Marcellus and North Louisiana.

Again, I think it's a great question and a really important one, because it highlights our ability to choose between two great assets each near key market areas in the Northeast and in the Gulf Coast. In both areas we have the ability to ramp production and are expected to get good growth next year relative to 2016, and we can do that for long time into the future.

Another key thing I think that's kind of a unique ability we have to react to upcoming changes. In capital allocation in my opinion is a real advantage that Range has that other companies don't have, or a lot of our peers don't have. So it's a function of several things. We've run multiple scenarios. You are right, Arun, we think as we continue to grow and ramp volumes, which we expect to do in North Louisiana, that costs that you mentioned will come down significantly, with time we can really drive down the processing and gathering costs.

Okay. My follow-up, some intriguing comments on capital efficiency gains in the Marcellus from longer laterals and existing, and using existing pads. Can you calibrate perhaps on a percentage basis what that could do for your Marcellus program in terms of just capital efficiency, in 2017 and 2018?

Yes. When you look at the pads, we have 230 existing pads out there, and I won't quote those numbers again that I went through in my remarks. But all of them represent tons and tons of opportunities to go back and drill laterals. We have literally got thousands of them that we can do.

With the infrastructure in place, of course when you go back onto an existing pad you don't have to build the pad, the road, meter taps, production facilities, the water infrastructure, all that stuff is already there. You can see savings on a per well basis ranging from $200,000 up to -- I mean there's one example in our presentation, for example is $850,000. They are not all going to be 850,000, they are not all going to be $200,000, I think every case is going to be specific.

As we roll into 2017 and we see as much as 1/3 of our wells potentially next year -- in our current plans today, which of course will change -- but when we look at it today we see maybe 1/3 of our wells next year on existing pads. That could move to as high as half of our wells potentially in 2018. I think over time you're going to see some major improvements to capital efficiency. I would peg it, if you tried to get back to a well-by-well basis somewhere between that $200,000 to $400,000, $500,000 per well on average, something like that.

Great. And then you're also going to be drilling longer laterals as well, right? (Multiple speakers). Average lateral length in 2016?

In 2016 I think our average drilled lateral length is probably around 7,000 feet or so. Next year we will see that going up to 8,000 feet. Of course our goal like I've said in the past is to continue to push those longer and longer. We believe in the liquids-rich areas. The wet and super-rich that around 8,000 feet might be optimum for us. In the dry we see them closer to 10,000 feet on average as we drill into the future.

Of course the wells that we turn into line may be a little bit less length than the ones that we are actually drilling because, remember again, you've just got the lag time of six, nine months, to a year in some cases, before the wells actually come online. But they will be stepping up right behind it year over year getting longer, just like the wells we are drilling.

Okay. Thanks a lot.

Pearce Hammond, Simmons Piper Jaffray.

Good morning. Thanks for the helpful disclosure on 2017 and 2018 production growth. What would CapEx be roughly to drive that production growth?

At or near cash flow.

Then, Jeff, what are you seeing on service costs on a leading edge basis, and what is your expectation for service cost inflation if any in 2017? Are you taking any steps to mitigate any of this potential inflation through maybe longer-term contracts?

Yes, Pearce, this is Ray. I will tackle that. It's a great question. Clearly we are at or near a bottom we think in service prices. I don't think anybody would disagree with that.

I think that the way prices on the service and supply side move from this point forward depends on -- it's going to be very regional, I will say it that way. I think in areas potentially like West Texas and maybe the SCOOP STACK areas and places like that where activity seems to have ramped up quite a bit more, you could see prices moving up. In the Marcellus per se, we don't see it.

We are entering into what we term long-term relationships, not necessarily contracts. I think contracts is a term that gets way overused when talking about service companies because every contact is different and has different outs and different resets, and everything else that people put in there. But we focus a lot on long-term relationships and we don't see any important or significant price increases going into 2017.

It's a little hard to see past that yet because I think a lot of it depends on commodity prices and what we see there. We're pretty excited about the future going forward. We've got two great plays. We can allocate capital freely back and forth between the two plays. We have organizations and opportunities in place to significantly ramp up both sides of that. So I think we have a ton of really high-class opportunities going forward, and I think we're going to be well-positioned to adjust to whatever happens on the service side.

Thanks guys and congrats on a great quarter.

Thanks.

Our next question comes from Doug Leggate, Bank of America.

Good morning everybody and thanks for the early look at the next couple of years. Ray, maybe Jeff, I guess the question we are all trying to figure out is the returns on Terryville look like they are on an apples-for-apples basis better than the returns marginally in the Marcellus given the differential challenges and so on. I realize you talked a little bit about allocation and relative rig counts. But how do you think about how far you would want to go in skewing the capital toward Terryville? Why wouldn't you go to the highest return assets in the portfolio now that you have that option?

Doug, I'd say if you look at the returns that are in our IR presentation on the website, and you look at them, they are actually close. Terryville was slightly better, but they are very close.

One of the advantages we have again that a lot of our peers don't have that are single-base center focused, is we can allocate capital back and forth. So as best as we can on a real-time basis we will be looking at making the best investment decisions we can. But we think that is an advantage we have that others do not.

I guess I was thinking more about the impact on basis differentials in terms of mix, Jeff. In terms of --

(Multiple speakers).

The economics that are in there reflect the current strip and basis differentials for both areas. And yet the returns in those areas are close. To the extent that changes we will do our best to allocate to maximize value.

Great. Thanks a lot. My follow-up is hopefully a quick one. It's really on the condensate pricing improvement. I know you touched on this last quarter. I'm just trying to understand, if you could walk us through, notwithstanding any confidentialities, how you were able to achieve a $7 bump in your realizations and whether that is sustainable going forward?

Doug. This is Chad Stephens. It's really a function of the purchaser has a lot of scale in the area, and they have some new assets that they needed feedstock for. Fortunately our light crude serves that, the asset that they just put in service well. It was a good fit.

So it is sustainable going forward?

Yes.

Great stuff. We'll see you in a couple of weeks guys, thanks so much.

Thank you.

Ron Mills, Johnson Rice.

Question on the extension areas of the Terryville Field. Thanks for the cross-section showing the depth and the thickness improving on the southern extension areas. The three extension tests Jeff, you mentioned, were spread across your position between the Driscoll Vernon-type areas, or along that cross-section. Where about are you testing those extension areas?

We have not specifically disclosed where they are. That being said, I've seen different -- I mean it's public data. I've seen some people spot them up already.

I think the important part is, Ron, is the point that you're making, is that they are far away from Terryville towards the southern edge, far apart from each other. So they are good tests of the 220,000 net acres to start to look at what does the other acreage look like? The cross section reflects the upside and as you go south it gets thicker. As Ray mentioned, there are multiple fields in the area, plus 50 vertical wells across the acreage. It kind of gives you a feel for what that potential is.

And based on the -- Ray mentioned with some detail actually, not just said they were encouraging -- Ray gave you some feel to direct comparison back to Terryville in terms of the amount of gas in place and thickness and quality of the reservoir. But and still until you get the long-term test you don't know, but we're certainly encouraged by what we see both quality, quantity and where they are located.

Is it fair to assume that -- were these wells drilled with your design, with your lateral targeting? Just trying to get a sense as to the initial results, how they will be drilled versus what your plans are in terms of lateral targeting?

Yes Ron. The wells were sighted by the Memorial team prior to Range really being involved. We were there but we were not really in control at that point. As far as picking the actual targets where we put the horizontal laterals into, that was a real team decision, and Range was very much driving the train and working with the Memorial team in that, and fully baked-in, fully supportive of what they picked. We all agreed to that up front.

So, yes, we were heavily involved in the completions. And of course the completion design is on our watch. We're executing those as we speak.

One last one in South Louisiana. Ray, the well you highlighted that came in about -- it looks like it's almost 15% or 20% above the type curve you had used to evaluate deal. I assume that well was drilled prior to the merger? I guess that's question number one, and then the second part of that is what drove that outperformance, especially if it did not have the benefit of such tight lateral targeting?

This is Alan. The well was completed prior to us taking over operations on it. Probably what drove the productivity of the well is the fact that it was completed 100% within the 100-foot target interval. To help put some color on this thing, it is a 4700-foot lateral. So the 30-day IP if you normalize it would be 43 million cubic quivalent a day. That's why it's very impressive. So it was 100% within the target interval. Obviously completion design continues to change over time, so some modifications were made there.

Great. Thank you so much.

Jon Wolff, Jefferies.

Hello guys.

Hey Jon.

Very intrigued by the 230 existing well pads in Southwest PA. Talked about a little bit in the past and I think you said a third of drilling would be on existing pads and 50% next year. Can you take us back in history. I recall that number being 10%, 15% only a year or two ago. Then you went a little fast and I was wondering if you could repeat the numbers of how many wells were sitting on each of those? I think you said, 69, 70 wells that had five or six wells on them. Could you go through that again?

Sure. 230 existing pads. Those are all new pads and pads that are in various stages of execution. There are 124 pads with five or fewer wells, and there are 59 pads with six to nine wells. In general, most of our pads have the capability of eventually 18 to 20 wells, so you can do the quick math there and literally there are thousands of that. It's page 19 in our new presentation on the website.

Those are Marcellus wells?

Those are just -- (multiple speakers). The existing wells are Marcellus wells. They could literally be in any formation. Because again, eventually we could be putting Utica wells in there, upper Devonian also if we chose to going forward. But there are literally thousands of Marcellus wells left by itself.

Okay. And then, going back in time?

Going back in time, we have of course been experimenting with going back on existing pads for years now and in fact there's an example in the presentation that has got about over two years of production history on it. It was a pad that we went on to a five-well pad and put two additional wells on it and we were wanting to answer three questions.

One, how much money did we actually save? Number two, did the wells interfere with the existing wells that were already there? And then number three, you know since we were going on to a pad that was already two years old, would the better targeting and the better completion designs -- in other words two more years of learnings -- would that really help the completion?

And the answer was as presented on that slide, we saved $850,000 per well, which is huge. The wells did not impact the existing target and literally the new wells were literally only targeted about 20 or 30 feet different from the original wells. So even in the same zone, which is only about 80 or 90 feet thick in that area, we were only about 20 feet apart in difference and we were 700 feet between wells and we did not impact the existing wells.

So that was a huge learning for us. We have repeated that several times since. And the third thing is, the wells after two years of production were 53% better producers than the original wells.

So you can start to imagine if you just go through that hundreds of times going forward in the future you can start seeing what sort of capital efficiencies you could bake into that. It is pretty impressive. So we have literally got a lot of that to do. I think a year or so ago we were about 10% on existing pads. This year I think we are probably less than that, hardly any on existing pads.

Another important thing that has happened this year is we have all of our HBP concerns are finished. So literally we have no more acreage at risk, so we no longer have to worry about that aspect, which allows us to, going forward, really focus our capital in the very best returns. That is what you are going to see us doing going forward. I think you'll see those numbers gradually increase. I don't think it will ever be 100%, because clearly we have got some really good areas like in the eastern part of Washington County in our dry acreage, where even a grassroots brand-new four well pad there has even got better economics than going back onto an existing wet or super-rich pad.

So I think it allows us real-time to allocate capital to the very best projects in the Marcellus, and now of course we have another world class asset in North Louisiana, which gives us another great option.

Just thinking about allocated costs, pad is somewhere $1.5 million to $2 million?

Yes, pads can be anywhere from $1 million to $2 million. Roads can be significant to insignificant depending on how long they have to be. Production facilities can be several hundred thousand dollars per well on the initial install. Meter taps can be pretty expensive, and then water infrastructure is super expensive.

Jon, we have a lot of people queued up for questions. I hate to say it but just to try to get a couple more questions out. Don't want to cut you off but see if we can get at least -- there's a bunch of people we aren't going to get to, but maybe we can get a couple more.

Mike Kelly, Seaport Global.

Appreciate that. Thanks. Jeff, hoping to get your thoughts pertaining to the 20% growth figure you laid out for 2018. On our model you get there just adding a couple of rigs. I'm curious given the bullish macro backdrop you laid out, great liquidity, great economics and $3.00 gas. If you attempted to push that growth rate maybe meaningfully higher, and wanted to gauge your willingness to outspend and get there.

I think an important part is, we're saying we can get that kind of growth which is great, 20% at or near cash flow with $3.25 and $60. Clearly we have large inventory, multi-year inventories in two really high-quality areas in Pennsylvania and in North Louisiana. So it gives us a lot of optionality to the extent prices are higher and cash flows higher, clearly we could ramp up and grow quicker. But our intent is to be at or near cash flow. We think 20% growth at our near cash flow organically is very strong.

Okay. Fair enough. A quick one. In Terryville you guys laid out the economic slide, $8.7 million well costs. It sounds like you are just starting to implement your own techniques there. It appears if you have a goal of, what you will get that well cost down to with John making the move down from Pittsburgh to Houston. Thanks.

That's a great question. It's hard to peg a number yet. But we have only had --.John's only had his reins six weeks, and has already had some great wins. So I will just characterize it as saying, it's going to be significantly better. I just don't know how to peg that number yet. We just need a few more quarters under our belt to understand where we can really go with that. Great. Thank you.

We're nearing the end of today's conference. Mike Scialla of Stifel.

Thanks. Good morning guys. Could you talk a little bit about the potential drilling inventory in just the Upper Red within Terryville and how the tighter lending interval may have an impact on that?

Mike, this is Alan. I think that when we went back -- let me take you back in time and talk out the acquisition, and how we evaluated this thing. As we went through we recognized the Upper Red was really the dominant producing interval at that point in time. We recognize that changing target interval, optimizing target interval was going to have, could have a material impact in terms of productivity per well. And well result and EURs could improve over what we're currently providing for you right now. With that, and we also think that also applies to the Lower Red and the Pink intervals as well. So the same type of thing is going to happen.

With that, it's going to give us a fairly significant inventory of locations throughout Terryville from the Upper Red down through -- the Upper Red, the Lower red and then up shallower with the two Pink zones. So not going to give you a specific number, but I can tell you it is going to give us a fairly significant inventory going forward.

Going back through the whole process, we think we will be able to grow productions down there fairly significantly and be able to drive down the gathering and processing rate as well because of the [pec]. And all be able to do it within cash flow, is what our acquisition models show. We think it's right in line with what we currently have.

Not trying to pin you down to a specific number, Alan, but just in terms of -- Netherland Sewell had some numbers out with MRD. Are those in the ballpark, or are you talking about something different?

I'm going to come back to our analysis. When we did our analysis we didn't look at Netherland Sewell's analysis, we didn't look at MRD's analysis, we did our own analysis. My answer on this thing is when people have asked me this, we have what we believe is our analysis going forward. There is a lot of confusion I think that has been out there historically between some of the different analyses that are out there. As we continue to roll through this thing and get our arms around it we will provide more clarity, probably toward year end.

Thank you.

This concludes today's question-and-answer session. I would like to turn the call over to Mr. Ventura for his concluding remarks.

Thanks for participating on the call. If you have additional questions please follow up with the IR team.