Range Resources' (RRC) CEO Jeffrey Ventura on Q1 2016 Results - Earnings Call Transcript

| About: Range Resources (RRC)

Company Range Resources Corporation (NYSE:RRC)

Q1 2016 Results Earnings Conference Call

April 28, 2016, 09:00 AM ET


Laith Sando - Vice President, Investor Relations

Jeff Ventura - Chairman, President and Chief Executive Officer

Ray Walker - Executive Vice President and Chief Operating Officer

Roger Manny - Executive Vice President and Chief Financial Officer


Doug Leggate - Bank of America Merrill Lynch

Neal Dingmann - SunTrust Robinson Humphrey

David Kistler - Simmons & Company

Dan McSpirit - BMO Capital Markets


Greetings and welcome to the Range Resources first quarter 2016 earnings conference call. This call is being recorded. All lines have been placed on mute to prevent any background noise.

Statements contained in this conference call that are not historical facts are forward-looking statements. Such statements are subject to risk 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 of Investor Relations at Range Resource. Thank you, sir. You may begin.

Laith Sando

Thank you, operator. Good morning, everyone, and thank you for joining Range’s first quarter earnings call. The speakers on today’s call are Jeffrey Ventura, Chief Executive Officer; Ray Walker, Chief Operating officer; and Roger Manny, our Chief Financial Officer.

Hope you’ve had a chance to review the press release and updated investor presentation that we’ve posted on the Web site. We’ll be referencing some of the new slides this morning.

We also filed a 10-Q with the SEC yesterday. It’s available on our Web site 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’ll be referencing certain non-GAAP measures on today's call. Our press release provides reconciliations of these to the most comparable GAAP financial measures. In addition, we posted supplemental tables on our Web site 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.

Jeff Ventura

Thank you, Ray. Since our last call, we continue to make progress on several fronts. On the marketing side, INEOS is now routinely picking up ethane at Marcus Hook and shipping it to Norway. At the same time, we are now loading propane on VLGCs and shipping it to various international markets. The ability to ship ethane and propane out of Marcus Hook is a significant competitive advantage for Range. As an E&P company, we’re now able to connect a large percentage of our NGL production to end markets, the buyers and consumers.

As represented in our guidance for 2016, it has a meaningful impact on both NGL production and pricing. Given our transportation contracts for 2017, approximately 70% of our natural gas is projected to be sold in markets outside of the Appalachian Basin, further improving Range’s expected natural gas differentials going forward.

By the end of 2017, we expect to increase the amount of natural gas to be sold outside of the Appalachian Basin to about 82% of production. On the asset sale front, we recently closed the sale of our Bradford County acreage in Northeast Pennsylvania. The sale price was approximately $112 million. This was our only non-operative position in the Marcellus.

We have also recently signed a purchase and sale agreement for a southern acreage package in the stack play in Oklahoma. We have agreed to sell around 9,200 net acres and approximately 5 million cubic feet equivalent per day of net production from approximately 200 wells in Blaine, Canadian and Kingfisher Counties for about $77 million. We expect to close by the end of May.

The remaining northern acreage packages predominantly in Major County, Oklahoma consists of approximately 19,000 net acres and is on trend in north of the existing stack play and is in the emerging Osage play. Given that this play and other plays are moving in a direction of our position, we believe this acreage will increase in value with time and additional drilling results. Our plans will be to keep it for now since it's primarily HBP and we’ll look at the possibility of selling it at a more opportune time in the future.

Importantly, with these two asset sales of approximately $190 million, we expect no increase in absolute debt in 2016 as compared to year-end 2015 based on current pricing. This type of neutral budget preserves our balance sheet and liquidity, while allowing the macroenvironment time to improve.

On the operations front, our team continues to optimize our development. We continue to improve both capital and operating efficiencies. Ray will discuss this and give some specific examples in his discussion. The Marcellus, specifically in Southwest Pennsylvania, will continue to be the focal point of our activity this year. As Ray will mention, we drilled some outstanding new wells and the performance of some of the older wells continues to impress.

Our third dry Utica well is performing better than the first two wells and appears to be one of the top wells in the entire Utica play. It's great to have 400,000 net acres of dry Utica potential beneath our Marcellus acreage, which gives us options down the road. The deciding factor for Range will ultimately be what are the economics of the Utica versus the Marcellus. We will allocate capital to the wells with the best economics. And right now, that means our Southwest Pennsylvania Marcellus development.

In 2016, we’re projecting lower well cost, the impact of improved price realizations, better transportation capabilities, and lower all-in unit cost. The capital efficiencies our team is achieving are very significant. This is particularly impactful when efficiencies are combined with the quality of the rock we have.

We believe this is one of the key differentiating investment attributes of Range and one of the reasons we’re able to replace production so efficiently with maintenance CapEx of approximately $300 million or less. We believe Range has the highest expected EUR recoveries on a per lateral foot in the southwest portion of the Marcellus play combined with the lowest cost per lateral foot.

For 2015, our expected finding costs, using current development cost to recover pud reserves, was $0.40 per mcfe, significantly lower than the expectations of other natural gas producers. In the price environment the industry is facing today, the ability to develop reserves more efficiently is a key advantage for Range. Utilizing a finding cost of $0.40 or better, coupled with our projected 2016 all-in cash cost and looking at 2017 strip prices, our projected unhedged recycle ratio approaches 2. As Ray mentioned on his last call, in our best areas, our projected unhedged recycle ratio was over 2.

In summary, the first quarter was meaningful for Range. We had a significant marketing project become operational. We’ve got non-core assets sales that further high-grade our assets and keep debt unchanged at year-end, and we continue to see improving well results across our acreage in Southwest Pennsylvania, all of which sets up Range well for 2016 and into 2017.

I’ll now turn the call over to Ray to discuss our operations.

Ray Walker

Thanks, Jeff.

What I’ll do this morning is cover our production guidance, provide some examples of cost reduction and efficiency improvements, give some color on well performance, and talk about some of the potential opportunities that we see going forward.

We continue to remain focused on capital allocation and our production growth is a result of high quality properties being developed by a strong technical team. Production for the first quarter came in at 1.38 Bcf equivalent per day with 33% liquids. And for the second quarter, we’re setting guidance at 1.41 Bcf equivalent per day, with 32% to 35% liquids. Of note, during the second quarter, we expect to fully replace all the production sold from our three sales and our annual guidance moves to the high-end of our previous guidance and is now expected to be 1.41 to 1.42 Bcf equivalent per day.

We believe this year will look very similar to previous years with sequential quarterly growth and our exit rate will be higher than it was at the end of 2015, setting us up well for 2017.

For the first quarter, we continued to drive down our overall unit cost, resulting in a reduction of 10% from the prior year's quarter. Basically, all of the categories beat guidance.

One particular item that I would like to call your attention to is the LOE. Our operating teams continue to operate more efficiently. And when coupled with recent asset sales, our LOE per mcfe is 37% lower than a year ago and 14% lower than the prior quarter.

Capital efficiency continues to improve. I’ll go through just a few examples from our operations in Southwest Pennsylvania. On the completions front, we completed 1,324 stages with 2.25 crews during the quarter, setting another record. Compared to the first quarter of 2015, with the same number of crews, this is a 28% improvement. March was a record month, with 526 stages. We averaged 7.1 stages per day per crew, which is an improvement of 9% from a year ago. And in spite of completing longer laterals, we completed 15% more wells in the quarter than a year ago.

You’ve seen our water costs dramatically improve as a result of logistics, planning and some creative new management tools, resulting in savings of over $350,000 per pad. These efficiency improvements resulted in a 31% reduction in total completion cost per foot of lateral compared to a year ago.

On the drilling side, for the first quarter, we achieved a 20% reduction in drilling costs per foot as compared to last year, while drilling 50% more lateral feet per day per well on average. Said another way, we drilled 50% faster and saved 20% on our drilling costs.

All of this helps us on two very significant fronts. First, we get better pricing from our service partners as they can count on very high utilization rates. While we don't make the terms of our service contracts public, what's important is that we believe that Range has the lowest cost per thousand foot of lateral in the basin.

And secondly, we get our wells to sales faster, reducing the time from capital spent to sales, therefore improving our capital efficiency. Essentially, with the same number of crews, we completed 15% more wells in the first quarter than we did a year ago. I'll refer you back to slide 8 in our updated presentation illustrating the improvements in capital efficiency that we’ve achieved over the past several years. These examples that I've just covered should clearly illustrate why we expect to continue to improve into the future. And most importantly, we continue to work safely and environmentally responsibly.

Our cost savings have not been at the expense of well performance. We continue to achieve outstanding well results. We recently brought online five wells on a new seven well pad in our super rich area. The wells had an average lateral length of 6,000 feet and were completed with an average of 31 stages. The wells were produced under facility-constrained conditions and had an average 24-hour initial rate to sales of over 3,300 barrels of oil equivalent per day, with 65% liquids.

Earlier in the quarter, we brought online a three well pad, also in the super rich area, with average initial production to sales of over 3,000 barrels of oil equivalent per day, with 63% liquids. It’s early, but clearly these pads may significantly outperform the averages and they represent examples of areas where we can focus more capital in the future.

In our dry area of Southwest Pennsylvania, we brought online two different pads worthy of mention. Together, these pads include ten wells, averaging 7,500 foot laterals, completed with 39 stages, with nine of those ten wells online, again under constrained conditions. The nine wells achieved an average initial rate to sales of about 16 million a day per well. These two pads represent opportunities in our dry gas areas where we have fairly new and low-cost gathering systems with ample takeaway and many more multi-well pads and long lateral wells that we can develop going forward.

On the last call, we discussed the flexibility of going back to existing Marcellus pads to drill additional wells. This morning, I’d like to get into more specifics on a few particular examples. The first example is the pad that has been described in our presentation for some time now and is currently on page 39 of our updated presentation.

About two years ago, we went back on to a two-year old Marcellus pad and drilled two new infill laterals between the existing laterals. In this particular example, because the pad, road, water infrastructure, production facilities and so forth were already in place, the wells were $850,000 less expensive per well on average than the original well, even though they were 50% longer laterals. The new wells were landed with improved targeting technology and completed with updated frack designs. And after 600 days, the new wells produced 53% more than the original wells. And importantly, the new wells, which were spaced at 700 and 900 feet, respectively, did not impact the production of the original wells.

A second example is in our dry area of Southwest Pennsylvania where we went back on to an existing three-well pad and drilled three laterals. You can see this example on page 41. The original wells had an average lateral length of 4,800 feet completed with 25 stages and the average initial 24-hour rate to sales, again under constrained conditions, was 22.6 million a day per well. The new wells were drilled about one year later, averaging almost 8,700 foot laterals completed with 45 stages, and under facility constraints have an average initial 24-hour rate to sales of over 34 million a day per well. That's a 50% improvement in initial rates over the older wells. This is one of our very prolific areas that’s performing well above our average type curve, with many opportunities to drill additional wells on this pad and nearby pads.

A third example is our wet area of Southwest Pennsylvania where we went back on to a two well existing pad and added five new wells with longer laterals and again newer completion technology. You can find this one on page 40. The original wells were completed in 2010 and had an average lateral length of 3,700 feet completed with 13 stages. And the average initial 24-hour rate to sales was 6.7 million a day equivalent per well. Five years later, in 2015, we completed five new wells averaging 1,500 foot laterals completed with 27 stages and these new wells had an average initial 24-hour rate to sales, again under constrained conditions, of 28.2 million cubic feet equivalent per day per well, which is over 300% improvement in initial in initial rates.

While we still have many new pads to develop, to restate what we said on the last call, we also have 124 pads with five or fewer wells in addition to 59 pads with 6 to 9 wells. This represents over 180 pads where we have the potential to go back and drill additional wells in any of our stacked pay intervals, whether it's Marcellus, Upper Devonian or Utica. While all these pads represent unique and different opportunities, it’s important to point out that we have the potential to drill wells with reduced capital as significant infrastructure is already in place, lower operating costs as we develop new efficiencies, less gathering and compression as limited incremental infrastructure is needed when you're on an existing pad, potentially improved performances in the previous examples, and very little to no impact on the existing production. All of this results in a step change improvement in capital efficiencies and an even lower F&D like I discussed on the last call.

Another added and significant benefit is the much shorter execution time. And we avoid the need for any additional surface disturbance. Again, it’s very early in our planning cycle, but we could potentially drill about 50% of our wells next year on existing pads and we believe the savings per well could range from $200,000 to as high as $500,000, depending on each particular situation. Some cases could be more. Again, we believe this is a unique advantage for Range.

As you know for years now, we've been showing type curves in our presentation on a normalized lateral length basis for the average of the actual wells that we’ll bring to sales in a given year, all under the actual constrained conditions. We believe our average EURs per 1,000 foot are the best in the southwest portion of the play and that’s among a strong performing group of our peers. We also believe our average cost per 1,000 foot are the lowest in the entire play. Again, these are the averages expected in a given year and we've always presented the prior year's production performance to support those type curves.

What I’d like to do now is steer away from the averages for a moment and point out a couple of specific areas. Let me began with an area in the dry gas portion of Washington County. This example consists of 22 wells from four separate well pads, in which we are projecting the average recovery is 3.1 Bcf per 1,000 foot. These wells have an average lateral length of 6,300 feet and the EUR is 21% better than our average dry gas area type curve. These wells have a minimum of 180 days and as much as two years of production history.

Based on the current cost to drill and complete these wells of $5 million, using a flat $3 NYMEX price, the internal rate of return is 61%. We’re planning on turning to sales this year an additional 23 wells from five pads in this area with an average lateral length of approximately 7,000 feet.

Referring to the previous example I described in the wet gas area, we turn to sales five wells, again, which is illustrated on page 40, will be drilled on an existing pad. The new wells have a projected EUR of 3.6 Bcf equivalent per 1000 foot of lateral. This is 22% higher than our average EUR for the wet area type curve. These wells have been online for 11 months.

Based on the current cost to drill and complete these wells of $5 million, the return on these wells, using a flat $3 NYMEX price, is 34%. We’re planning on turning to sales over the next 12 months an additional nine wells from two pads in this area, with an average lateral length of over 5,800 feet. We expect to continue with longer laterals going forward.

In 2014, our average lateral length drilled was 4,915 feet. In 2015, it was about 6,300 feet. And this year, we expect the average to be about 7,100 feet. While it's still early in our planning cycle for 2017, we expect to drill wells that average around 8,000 feet of lateral lengths. Ultimately, we expect we’ll be drilling 10,000 foot laterals on average in the dry area and probably slightly less than that in the liquids areas.

Just as a point out, we’re planning to turn to sales two wells later this year in the range of 9,500 foot laterals and we’ll also drill three laterals over 13,000 feet this year with the longest planned for 16,220 feet of lateral length.

Importantly, our HP efforts are largely behind us after this year. Our land budget in 2014 was over $200 million. In 2015, we spent approximately $70 million. And this year, our land budget is reduced to approximately $20 million. Our development plan has positioned us to increase our flexibility going forward by allowing us to focus our capital on the very best return projects.

While our 2017 plans are still under development, the important things to remember are: We have a large core position, low-cost structure, strong capital efficiency, drilling longer laterals, an attractive transportation portfolio, ability to drill on over 180 existing pads as well as new pads, ability to focus on our best and most prolific areas, ability to increase liquids production when economically warranted, a low decline base production, very low maintenance CapEx, and finally strong operations and technical teams with a proven track record.

To the answer the common question about maintenance CapEx, if you consider what I've discussed here this morning regarding our ability to drill on existing pads, along with targeting some of our better areas, and couple that with our low base decline rate of approximately 19%, we have the ability to hold our 2007 production flat to this year's expected exit rate for $300 million or less.

We believe this low level of maintenance CapEx makes our production incredibly resilient if prices were to stay low, while providing us a solid base to grow from when the supply and demand equation improves and prices move higher. The point is that whatever prices do and wherever we set the drilling throttle, having a really low maintenance CapEx works in our favor.

Shifting to marketing, utilizing our Mariner East transportation, Range loaded the very first VLGC from the East Coast with 550,000 barrels of propane on March 19. Range also saw the first INEOS ship set sail from the East Coast during the first quarter. Both ethane and propane ships are now leaving Marcus Hook on a regular basis and having international exposure for our products is expected to benefit our net back pricing going forward.

Looking ahead, our next transportation option coming into service is the Texas Eastern Gulf market’s expansion project expected to start later this year. This project will allow us to ship more production to the Gulf Coast region, anticipating a positive impact to our sales portfolio.

By the end of this year, we’ll have about 70% of our gas sold outside the Basin. And like Jeff said earlier, by late 2017, we’ll have over 80% of our gas sold outside the Basin, which we expect to result in better net back pricing.

As a further update, on our third Utica well, the DMC 10H is currently shut in for facilities build out and an extended bottom hole pressure buildup. We expect to bring the well to sales in about 60 days. The just over 30-day flow-back test initiated immediately after completion, again with no aging, averaged 18.3 million a day to sales with the gas rate essentially held flat with high flowing pressures. You can see how this well’s performance compares to some of the nearby and noteworthy Utica wells drilled by our peers on page 35 in our updated presentation.

Early data indicates that this well could be one of the top wells today in the play. Our current expectations are that the well will be put to sales at approximately 12 million a day. The first phase of the reservoir modeling suggests it should hold that rate flat for approximately 500 days before declining. We’ll know a lot more in a few months once we complete the next phase of our data acquisition and modeling and the well is actually put to sales. But, again, early indications are good.

As most of you know, the Utica cost almost 2.5 times more than our dry Marcellus. And while the Utica represents tremendous future resource potential, even with anticipated efficiencies, the returns from our Marcellus wells currently far exceed Utica returns.

Given limited production history thus far, on a risk-adjusted basis, it’s clear to us that our high quality Marcellus wells are the superior investment. Our Utica potential is held by our Marcellus development and over time we expect that Utica can be a complementary development opportunity. But, for now, our plan for the rest of this year is to monitor our three wells along with the offset well, while continuing to build our reservoir models and then determine the path forward from there.

In the meantime, we’ll remain focused on high-graded Marcellus core acreage with the best economics possible. As we continue to lower costs, improve efficiencies, drill longer laterals, and develop our core assets, we remain well positioned to create value.

Over to Roger.

Roger Manny

Thanks, Ray.

There were many successes in the first quarter of 2016 as Range continued to effectively position the company for the current economic environment and a future with higher takeaway capacity and better pricing.

Starting with the balance sheet this time, we ended the quarter with less debt than we entered and our capital spending plans are right on track to produce prudent growth in production and reserves with improving capital efficiency.

A major highlight of the quarter was the unanimous reaffirmation of our annually-determined $3 billion bank credit facility borrowing base. Beyond the committed liquidity it provides, looking behind the numbers at the approval process reveals three significant positive read-throughs.

First, the reaffirmation excluded the collateral value associated with the December 2015 Nora sale and the two more recent asset sales, which in aggregate exceeded $1 billion in sale proceeds in the unique portfolio of value-added marketing arrangements we have for our natural gas, NGLs and condensate, which will improve future pricing.

Our recycle ratio, based on our year-end 2015 reserve report F&D cost, projected 2016 unit cost structure projected 2016 basis to NYMEX and current unhedged strip price for 2017 is approaching two times, ensuring that we can continue to grow our reserves and production within unhedged future cash flow. As I mentioned on last quarter's call, we believe, an underappreciated element, that balance sheet strength and preservation is having an unhedged recycle ratio above one times which allows for both growth and debt reduction at the same time over time.

Our first quarter ending debt-to-EBITDAX ratio for the past three years has been 3 times, 2.8 times, and 2.9 times respectively. The ratio at the end of this year's first quarter is a very manageable 3.3 times. As a reminder, Range has no debt-to-EBITDAX covenant, no bond maturities till 2021, $1.3 billion in freshly committed liquidity, low maintenance capital requirements, complete control over our capital spending level and timing, and a robust recycle ratio well over one time.

With prices improving, our recycle ratio will also continue to improve and the debt-to-EBITDAX ratio will eventually crest over or decline with no negative impact to our operations.

Turning to the income statement, comparing the first quarter of 2016 to the first quarter of last year, the impact of 45% lower realized prices could not be offset through production growth and cost reductions. First quarter net loss was $92 million, largely prompted by a $43 million pretax impairment of certain Oklahoma properties.

First quarter earnings based on analyst methodology, which eliminates non-cash and non-recurring entries, was a loss of $17 million or $0.10 per fully diluted share.

On the cost side of the ledger, cash unit cost were down $0.01 from last year and total unit costs, including DD&A, was down $0.29 from last year. All cost categories came in below guidance with direct cash operating costs at $0.19 per mcfe, breaking the $0.20 level for the first time. The main reason for the large operating cost beat was the absence of a severe winter and the avoided cost of tending to our wells with added shifts during periods of extreme cold.

Transportation, gathering and compression were also well below guidance at $1 per mcfe. This positive variance to guidance may be attributed to lower costs associated with our production mix and also lower transportation costs that were avoided due to the delayed full system startup of the Mariner East project.

Second quarter expense guidance may be found in the earnings release and other useful costs and hedging data, as Laith mentioned, may be found in the supplemental tables posted to the Range Web site.

Cash flow for the first quarter was $99 million and cash flow per fully diluted share was $0.59. First quarter EBITDAX was $135 million.

Range remains well hedged in 2016, with more than 80% of our 2016 gas production carrying a floor of 3.22/MMBtu. As 2017 and 2018 NYMEX gas prices have improved and because our full cycle cost structure is so low, we have commenced limited natural gas hedging in these years to reduce downside price risk and ensure cash flows available for growth.

We’ve also added to our NGL hedge position during the quarter, the details of which can be found in the 10-Q, earnings release and on the Web site.

To summarize the first quarter, we’ve continued to successfully shed non-core assets, decrease debt, reduce our cost structure and improve our capital efficiency, while delivering consistent growth. Looking ahead, we see continued disciplined growth with even better capital efficiency, plus improved pricing from our new ethane, propane and condensate marketing arrangements. As Ray described in his remarks, this really sets us up well for 2017 and beyond.

Jeff, I’ll turn it back to you.

Jeff Ventura

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

Question-and-Answer Session


Thank you, Mr. Ventura. [Operator Instructions] Our first question comes from the line of Doug Leggate from Bank of America Merrill Lynch. Please go ahead.

Doug Leggate

Thanks. Good morning, everyone. Good morning, Jeff.

Jeff Ventura

Good morning.

Doug Leggate

Jeff, first of all, congratulations on another very strong operating quarter given the circumstances. But, I guess, the question that seems to be getting asked to a lot of your oily peers is, is there a level when you would consider putting rigs back to work? Now, I realize $2 gas price may be a little premature or certainly irrelevant in this market. But just conceptually, given the efficiencies that you have baked into the system, given the continued improvement you delivered for the last several years, what is your philosophy in terms of how you see Range’s longer-term targets evolving, assuming that gas prices do improve? And I’m thinking back to when you used to talk about 20-plus growth as an annual run rate in the longer-term.

Jeff Ventura

That’s great question. Let me talk about it in a very conceptual way. Again, I think we’re in a great position. We’re in the highest quality gas play that’s there with economics, I think, that really rival any play. It’s a stack pay area. By the end of this year, it’s predominantly HBP, so we’ve got a lot of optionality not only in drilling Marcellus, Utica, or Upper Devonian, but drilling wet or dry.

We’ve got really low maintenance CapEx, which I think is important. And I think is – if it isn’t best-in-class, it’s clearly right up there. Coupled with really good marketing agreements. Now, there are a lot – our newest piece that’s in place, Mariner East. So the ability to move ethane, propane or natural gas really to multiple markets around the US or even internationally, the ability to go back on existing pads, those are all key things.

So I think what you’ll see is too is we’re in great shape in a low-price environment. We believe that a lot of good fundamentals are setting up for natural gas to improve. We think this will be the first year natural gas supply rolls since 2005 or something back like that, coupled with a time where demand is coming up.

So in a lower – for a longer scenario, we are well-positioned. In a higher price scenario, we have a lot of optionality. Ray has talked about it and can continue to talk about. I think when you look at our fracking efficiency, it’s probably best-in-class or right up there, our drilling efficiency and wells. So we have the ability to ramp when need be. But we’re going to be very returns-focused. We’ll be sensitive to balance sheet and those types of things. So we have – we have a lot of optionality to push the throttle forward or to pull it back, which is, I think, the position that we want to be in.

So that’s kind of a long-winded answer, but I think philosophically we’ll think about the returns we’re getting. We’ll think about the balance sheet and all those types of things. But we have a lot of optionality with what we have. The team continues to get better, better and better as evidenced by the capital efficiency and we have tried to slice and dice that in multiple ways, everything from a high-level graph that shows our capital efficiency to some of the specifics. And, again, feel free to ask Ray about some of those. I think when you look at them versus peers, they are impressive numbers.

So that’s kind of philosophically how we look at it.

Doug Leggate

I guess what I’m kind of struggling with this if you assume any kind of modest recovery in gas prices, you could pretty much make your growth rate whatever you wanted it to be. So I’m just trying to think how you would trend limits around that, whether it would be balance sheet or some kind of EBITDA coverage ratio or…?

Jeff Ventura

Yeah, yeah. Clearly, balance sheet is important. Spending typically is going to be – I think, philosophically, is going to be at or near cash flow – or at on your cash flow. But I’ll basically leave it at that. Roger, do you want to add on to that a little bit or…?

Roger Manny

I think, Doug, it’s going to be game time decision when we move forward and we’re just going to read the market and we’re going to look at all the dials and adjust the throttle accordingly. I just don’t think it makes any sense to try to lock into a number right now. It’s too dynamic.

Doug Leggate

Absolutely, I understand. My other question is really just a little bit more – it’s less about the operations and more about the disposal program. You held on to the stack, Jeff. I’m just wondering what we should read into that. Are you looking for a better market? Or are you thinking – if that’s something you might want to put your own capital to work in at some point?

Jeff Ventura

Let me clarify that one. We marketed that in two pieces. The southern package was actually in the stack play. It was about roughly 9,000 acres of – scattered across three counties, kind of small broken up pieces, but in the play, collectively producing about 5 million per day equivalent net from 200 wells – 200 all legacy, vertical wells. You can do the math there. So the price that we got for that, we thought, was a very strong price for that kind of position, particularly in today’s market.

When you looked at the northern piece, which is bigger, and about 19,000 net acres, it’s mainly in Major County – predominantly in Major County, which is north of the stack play. But the play is clearly moving in that direction and there’s rigs coming right up to us. And it’s also in the emerging Osage plays and there is other plays. So we actually have eight rigs drilling in and around us. It’s all HBP. So our thoughts are to just wait, watch some of the drilling results that we expect will be good and just sell into a better price. So we have – because it’s HBP, we have the optionality of time. So I think you’ll see us sell that and market it in due time.

There’s a lot of drilling activity. You can take a map of our acreage. It was up on our Web site at one time or the IR team will give it you. You can look at the active rigs, I’m sure, if you subscribe to those services. There’s a lot of activity around us.

The remaining stuff we have in the Panhandle and up in the northern Oklahoma, I think you’ll just see us sell us with time, but we’ll do it at an opportune time. It’s similar to the Nora sale. We didn’t just – Nora, we had to find the right buyer at the right time. We were very pleased with the sale. Hopefully, it’s a win-win for both sides. But it’s finding that buyer that really likes the asset. Bradford County was the same thing. I know people that follow us, we had that for sale for a long time. We’re very disciplined and we finally found the buyer that paid us what we thought was a price.

I think if you look at both of those cases, the price we got was about double what most of the people thought Nora or Bradford County was worth. So I think the remaining stuff in Oklahoma, particularly that northern part of the acreage in Major County, it’s just picking the right time and the right buyer. But you’ll see us sell that with time.

Doug Leggate

Great stuff, Jeff. Yeah, we’re watching you very closely, as you say. I’ll let someone else jump on. Thanks a lot.

Jeff Ventura

Thank you, Doug.

Ray Walker



Thank you. Our next question comes from the line of Neal Dingmann from SunTrust Robinson Humphrey. Please go ahead.

Neal Dingmann

Morning, guys. I certainly would echo Doug’s comments. You were great operationally. Jeff, one question for you, and then more to Ray on the efficiencies. Just on that last question, Jeff, additional non-core sales, just kind of wondering what else you’re seeing out there besides, obviously, you had two strong sales here recently. Are there other things you could tee up here shortly?

Jeff Ventura

Clearly, I think the Major County package, it’s probably marketable. I hate to always put time frames on them. But I think, later this year, or at the optimum time, we would definitely consider that stuff. In the Texas Panhandle, we have a nice position that. It’s non-core to us. There’s other people that really like that area. Mississippi, and again, and you can even – we carved off Bradford County, so it was a little slice of the Marcellus that wasn’t key to us that was important for somebody else. You can envision things like that with time.

Neal Dingmann

Okay. And then, maybe for Ray, I was definitely intrigued by our comment that 50% plus of you wells, as you mentioned, next year could be on older pads. And so, I’m looking at that, plus, obviously, just doing the bigger pads, the six to nine-well pads. Ray, based on that and those type of efficiencies, what type of cost savings are potential? It looks to me like it could be quite large.

Ray Walker

It’s a great question. It’s more of a continual process. If you look at page eight in our presentation, we show what we’ve been able to do literally and what I think that matters at the bottom line is the total cost per lateral foot. And you look at that over the years and you’ve seen really good improvement. And even the cross years where service costs were actually going up, we were making significant improvements. A lot of that’s driven by drilling longer laterals. It’s just the fact that our teams and our service crews are getting more and more experienced, all of those things factoring in, are allowing us to keep doing what we’re doing. And I think that we’re going to see probably half of our wells – could be less, could be more – we’re really, really early in the planning cycle at this point. But some of the things I talked about in my prepared remarks – and when you couple the savings or the fact that you don’t have to build pads and roads and production facilities, other things that we don’t talk a lot about, or things like survey, land, title curative, we’ve got water infrastructure and depending on where that pad is in relation to the current water infrastructure we have in place, all of those things you could save couple of hundred thousand dollars a well or you could save up to $850,000 a well depending on the particular situation.

And I think those kind of savings are real. I think it’s taken us lots of years to develop a very large core asset area. We’ve got a great low base decline rate which allows us to build very efficiently with the capital that we allocate. We’ve got some – clearly some really high prolific performing areas, like I went through them in my remarks. Couple of examples there that we can focus on. We’ve got new infrastructure that’s always continually still being built, like some of the new dry gas stuff I talked about in my remarks.

So I think it’s just all – and you roll all that together, the fact that we’ve got a great transportation portfolio, we’ve got diverse outlets for operational aspects and as far as pricing aspects, a lot of these things have taken years to develop. All of our HBP concerns are covered this year. And so, we’ve got a great future going forward. And I think we can just continue that capital efficiency. The service contractors can continue to give us great pricing because of the high utilization rates. We don’t think anyone else in the Basin is operating at the number of fracks per day that we are or anywhere close. So I think there is a lot of things out there like that that just give us a pretty unique advantage when you compare us to all of peers.

Neal Dingmann

Great, great. And then one last one, if I could. I love that slide 15, your gas and plays. I know you and Bill were probably the first ever to put that out there. And I’m just wondering, number one, is that continuing to grow? Obviously, you look where that red area was and, to me, you guys have been dead right here now for the last couple of years on that. Two questions, I guess, around that. One, do you see that expanding at all or are you pretty content there? And then secondly, when you do some of these dry Utica gas wells there, in order to keep the cost down, what things can you do? I guess because of the pressure, do you still have to use the ceramic versus the sand? I’m just wondering what things you can do in that area to keep the cost down on those dry Utica wells?

Jeff Ventura

All right. Two great questions. I think the gas and plays math, we’ve had for a long time internally. And then, of course, we made them public, I guess, two or three years back. And they’re actually holding very true. I think, as we’ve seen, more and more development occur in the Utica and in Upper Devonian and, of course, in the Marcellus. I think they’ve held really true. I think it’s going to be like – most plays, historically, have been where the true core sweet spots tend to shrink and so forth. I think that’s a big reason behind our low base decline rate, is I think we have better hydrocarbons – better hydrocarbon content, I should say, better perm, better porosity, better pressures. So we get better desorption of gas in the long run, a lot of those things help us. But I think they’re going to hold pretty true. Clearly, the Utica is really early, especially on the Pennsylvania side. But we’re pretty pleased about that.

Going forward on the Utica, we think when we get ready to do the next well and we’re not sure when exactly that’s going to be yet, but we can do, based on what we know today, a 6,500 foot lateral for around $12 million – probably less now. An 8,000 foot lateral or so, we can probably do for about $14 million or less. We think that’s probably an industry-leading cost already. We’re a little bit shallower than some of the other wells. So there’s a little bit less cost there.

We, in our last well, completed it with – I think it was 5,800 feet with 38 stages and we were 500,000 pounds per stage and it was 50/50 100 mesh and 40/70 premium white sand. So we don’t think ceramics is going to be necessary, at least in our acreage. That’s going to keep cost way down.

Of course, every well that you get under your belt, you learn a lot more, so a little bit less science is required. We will continue to drill these wells on existing Marcellus pads. So you’ve got a lot of savings there, like we’ve talked about previously. And I think all of those things set us up well. We’re pretty convinced, the 400,000 acres is going to be really high-quality stuff. But at this point in time, as good as we can do, it’s still 2.5 times more expensive than a dry gas Marcellus well in the eastern part of Washington County. And when you look at that, some of these Marcellus wells that I talked about in my prepared remarks, we’re making about the same volume, if not more, in a year’s time. And we can get it for 2.5 times less dollars. So that’s where we’re going to focus our capital, especially in this market.

But do we believe the Utica can be a big deal going forward? Yes. Do we believe it can be influential? Yes. Do we believe it’s going to be competitive? No. We think it’s going to be complementary because it’s something that’s stacked with our Marcellus stuff. So I think that’s where we see that going forward. But we’re very encouraged. And again, I’ll refer you to page 35, I think it is, in our presentation and look at how it performs versus some of our offset peers’ wells that have been real noteworthy and they’re all great wells. No doubt about it. But I think what we’re seeing is our acreage can be right up there among the best acreage that there is in the play.

Neal Dingmann

Very helpful, guys. Thanks so much.

Ray Walker

Thank you.


Thank you. Our next question comes from the line of David Kistler of Simmons & Company. Please go ahead.

David Kistler

Good morning, guys. And great work. This goes back to kind of the existing pads and the cost savings that you talked about there. Obviously, the low-hanging fruit is the fixed cost component, the pads that are there, the tanks, the roads, et cetera. But can you give us a little bit more breakdown in terms of how you guys think about it in terms of what it does to the actual operating cost metrics and the gathering side of the component and how that will flow through and whether that's truly captured in this $250,000 to $850,000 well savings you talk about?

Ray Walker

Yeah. Dave, this is Ray. It’s a great question. Again, the savings – the $200,000 to $500,000, let’s say, or $600,000, whatever it might be in a particular case, that’s going to be the dirt work, things like building the pad and the road, then you’ve got the actual production facilities which, as you know, the separators, the production tanks, the heater treaters, all those different things. They’re going to be different in the super rich versus the wet versus the dry area. They’re all different. I think people tend to group this together and say, it’s going to be the same all the way across and they forget that, number one, we have a really large position and, number two, it’s really diverse. So we’ve got lots of different designs of facilities that we deal with. But it’s going to be all of the meter taps, things like that. Then you’ve got things like damages that you pay the landowners, survey cost, title curative, you’ve got a lot of different things like that that we don’t talk a whole lot about, which are really significant.

You’ve got water infrastructure. If it’s a pad that’s right near an impoundment or right on a pipeline network, of course, the water cost could vary by several hundred thousand dollars on a pad. And some of the new things that we’re doing lately, today, we’re saving, on average, probably $300,000, maybe $350,000 per pad on water cost. It’s that significant when you’re drilling a new four-well pad. It’s really significant if we just go back and add one or two wells on a pad. So I think those things are – all the capital costs that roll in there.

If you think about going back on to an existing pad and there is room in the gathering system, which is why we would go back on to an existing pad, you don’t have to add any more compression or low pressure pipe. And when you do that, that’s a significant part of the cost in our gathering, compression and transportation line, which is – I think it was $0.99 or whatever it was for the first quarter. Significant piece of that is that low-pressure gathering and compression charge.

When you go back with an existing well, you could see those numbers be a lot less. I’m not going to quote a number because they’re all different. But it could be – most of that cost goes away essentially. You’re really only looking at the variable cost of fuel and a few little things like that, of putting that new production online into that existing system. So there are a lot of things like that that help us.

And as far as LOEs and things, the way it helps you there is, basically, you’re not adding new equipment and new infrastructure that you have to add new lease operators for to cover. In other words, going back on to an existing pad doesn’t cause us to add more personnel, it doesn’t cause us to really add a lot more chemicals or maintenance or anything else like that. It’s the kind of stuff that’s already there and being operated.

So I don’t know, that’s a long-winded, roundabout way to talk about some of those things. But all of that helps us reach the capital efficiencies that we are with. And again, this has been a process that we actually talked about in the very early days, way back in 2007 and 2008 when we started drilling and building some of these pads. And it’s been a goal all along to build these pads where we can go back and drill as many as 10, 15, 18 wells in some cases. We were always really focused on the fact of having diverse outlooks, diverse pricing scenarios for our products, and not being dependent upon any one situation or project. All of those things have really helped us. And this year’s really a turning point here for us because of some of the big projects like Mariner East coming online. Spectra's Uniontown to Gas City was a pipeline project that we worked on for years. Later this year, we’ve got the Gulf Coast project coming online. All of those things have taken years to put in place. And I think that’s a very unique part of our story going forward.

David Kistler

I appreciate that color. That’s fantastic. Maybe kind of building off on the last point there, when you guys start selecting which pads to go back to, can you talk a little bit about how much maybe closest proximity to highest price markets factors in? You already indicated a little bit in terms of how important it is to be closer to various infrastructure just in terms of being able to get that gas or NGLs to market. But how much of that factors in also to the decision of how you select the pads and the timing of when you’ll be going back to various areas, whether it be super rich, wet, dry, et cetera.

Ray Walker

That’s a great question, Dave. And it’s really all of that. Plus, I would add in there, it’s not always going to be going back on existing pads because we have some – in some of the stuff I talked about in my prepared remarks, some of these wells that – I talked about the recent performance and then some of the existing wells that we’ve done and following up, like that example of the ten different wells from several different pads. When you look at that, the economics on that stuff – even if you build a new pad is probably better than going back on the existing pads in today’s world in the wet and super rich area. So we’ve got that flexibility to go both ways. And it really comes down to what gives us the best overall project return for our capital in a year’s time. Where are we going to be able to – if you put a dollar in, where are we going to get the most dollars out? And it’s really that simple. But we have to factor in all those things you talked about, whether it’s markets, proximity to infrastructure, timing of sales that we’ve done with customers, all of those different things factor into that.

David Kistler

I appreciate the added color and great to see the scale and scope is now really starting to kick in on the asset base.

Ray Walker

Thanks, Dave.


Thank you. Our next question comes from the line of Dan McSpirit from BMO Capital Markets. Please go ahead.

Dan McSpirit

Thank you. And good morning, folks.

Jeff Ventura

Good morning.

Ray Walker

Good morning.

Dan McSpirit

Couple of questions quickly, if I may, on cash margins. Regarding your guidance on differentials in NGL pricing, what potential do you see for that to change either the back part of this year or periods beyond that? Can we see narrower differentials on more gas leaving the basin and better NGL pricing on barrels being shipped than what’s guided?

Jeff Ventura

I will maybe tag-team that. But I think if you look on slide 14, it shows projected average differentials in 2016 versus 2017. So we were expecting those differentials for the year to average $0.40 to $.45 less from NYMEX. Into 2017, the expectation is that could improve to $0.25 to $0.35. We expect significantly better NGL pricing this year as a result of new contracts and movement – Mariner East starting up, plus some of the early things where we have kind of that optionality to either export or move in the US markets. Again, being a competitive advantage being the only producer who has capacity on Mariner East. But when you look at slide 14, coupled with some of the slides in there about the NGLs, we think that we’ll see significant improvement.

Dan McSpirit

Okay. And then a follow-up to that, just confirming that your guidance on transportation costs capture the increase in production being priced outside of the Appalachian Basin, just inquiring, again, just to assess the risk to cash margins here going forward.

Ray Walker

This is Ray. I’ll answer that. All of those projections that we put in there going forward are based on the current deals and transportation deals like Spectra's Uniontown to Gas City, cost some money to send the gas over there. But we, net-net, end up with a much better revenue because we got a much better realized price for our gas.

Same thing on the NGLs. We’re now transporting 75% of our barrel, ethane and propane, out of Appalachia. The VLGCs on the propane is saving us a nickel a gallon. On a $0.50 a gallon product, that’s a big deal. We’re hedging international spreads on probably a third of our second half of 2016 production and that’s looking really good. Shipping rates have come down to $0.04. They could go lower. We’re hearing lots of good things about the propane market and we’re hearing lots of good buzz about the ethane market. So we’re pretty encouraged going forward. Can’t peg down exactly when it happens, but I think, again, with us focusing on our low-cost structure, multiple outlets not being dependent upon any one particular project, we’re set up really well going forward.

Dan McSpirit

Got it, thank you. And many thanks for taking my questions. Have a great day.

Jeff Ventura

Thank you.

Ray Walker

Thank you.


Thank you. Ladies and gentlemen, we have now reached the end of the time limit for our Q&A session. And this will conclude our question-and-answer session. I would now like to turn the call back over to Mr. Ventura for his concluding remarks.

Jeff Ventura

Thank you very much for participating on our call. If you have additional questions, please follow up with our IR team.


Thank you, ladies and gentlemen. This does conclude our teleconference for today. You may now disconnect your lines at this time. Thank you for your participation. And have a wonderful day.

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