Range Resources Q1 2016 Results
Range Resources Corporation (ticker: RRC) reported its Q1 2016 earnings . Following are highlights from the quarter with a conference call recap.
Q1 Highlights
Unit costs reduced by 10%, or $0.29 per mcfe compared to prior-year quarter
Completed and contracted asset sales announced totaling approximately $190 million of proceeds
Absolute debt levels reduced by $631 million over the last twelve months
Existing $3 billion bank credit facility borrowing base unanimously reaffirmed by all 29 banks
Marcellus production up 17% over prior-year quarter
Well productivity drives production towards high-end of annual guidance
Range becomes the first North American company to export ethane to Europe
Peer-leading Marcellus well costs driven by operational improvements
Recently completed Utica dry gas well appears to be one of the best in the play based on early data
Asset Sales
Range closed the sale of its Bradford County non-operated Marcellus assets on March 28, 2016 and received approximately $110 million of proceeds. The Company sold an average working interest of 23% covering approximately 10,900 net acres with net production of approximately 22 Mmcf per day, which is included in our reported first quarter results through closing.
In April, Range signed a purchase and sale agreement for certain assets located in central Oklahoma for approximately $77 million, which is expected to close in the second quarter. The assets consist of approximately 9,200 net acres and approximately 5 Mmcfe per day of net production from approximately 200 wells in Blaine, Canadian and Kingfisher Counties.
Following the closing of this sale, the Company will still own approximately 19,000 net acres in central Oklahoma. The retained acreage, which is primarily held by production, is in the northern extension of the STACK play and includes Osage and other reservoir targets. Multiple tests are currently being drilled near Range’s acreage.
Bank Credit Facility
The Company’s existing $3 billion borrowing base and $2 billion commitment amount under its $4 billion bank credit facility were unanimously reaffirmed by its 29 lenders with no changes to the financial covenants. The credit facility matures on October 16, 2019 and is subject to annual redeterminations, which are required to be completed by May of each year. The balance drawn under the credit facility at March 31, 2016 was $31 million.
First Quarter 2016
GAAP revenues for the first quarter of 2016 totaled $331 million (28% decrease compared to first quarter 2015), GAAP net cash provided from operating activities including changes in working capital was $87 million (a 58% decrease as compared to first quarter 2015) and GAAP earnings were a loss of $92 million ($0.55 loss per diluted share) versus earnings of $28 million ($0.16 per diluted share) in the prior-year quarter. First quarter 2016 results included a $43 million proved property impairment related to legacy assets in Oklahoma. First quarter 2016 also included $87 million in derivative gains due to decreased commodity prices, compared to a $123 million gain in 2015 and deferred compensation plan expense of $16 million compared to $6 million of gains in the prior-year quarter.
Non-GAAP revenues for first quarter 2016 totaled $354 million (19% decrease compared to first quarter 2015), cash flow from operations before changes in working capital, a non-GAAP measure, was $99 million. Adjusted net income comparable to analysts’ estimates, a non-GAAP measure, was a loss of $17 million ($0.10 loss per diluted share) for the first quarter 2016 compared to earnings of $31 million ($0.19 per diluted share) in the prior-year quarter. The Company’s total unit costs decreased by $0.29 per mcfe, or 10%, compared to the prior-year quarter.
Capital Expenditures
First quarter 2016 drilling expenditures of $130 million funded the drilling of 24 (22 net) wells. A 100% success rate was achieved. In addition, during the quarter, $5 million was incurred on acreage purchases, $1 million on gas gathering systems and $4 million on exploration expense. Range is on target with its $495 million capital budget for 2016. The Company expects to average three rigs running throughout 2016.
Operations
Marcellus Shale
Production for the first quarter averaged approximately 1,330 net Mmcfe per day for the Marcellus Shale divisions, a 17% increase over the prior-year quarter. The Southern Marcellus Shale Division averaged 1,097 net Mmcfe per day during the quarter, a 24% increase over the prior-year quarter. The Northern Marcellus Shale Division averaged 233 net Mmcf per day during the quarter, an 8% decrease over the prior-year quarter.
Operational efficiency gains continued in the first quarter. In the southern division, Range completed 1,324 stages during the quarter averaging over 7 stages per day per crew, which is a 9% improvement compared to the prior-year quarter. During the quarter, the Company drilled 50% more lateral feet per day per rig, on average, when compared to the prior-year quarter. This drilling improvement helped lower drilling costs per foot by 20%. These and other efficiencies have driven Range’s normalized (per 1,000 feet of lateral) well costs, including surface facility costs, lower than any other Marcellus peer, as shown in the latest Company presentation.
Range also completed its third dry gas Utica well in southwestern Pennsylvania during the quarter. After producing to sales for approximately 30 days, the well is currently shut-in, waiting for completion of surface facilities and allowing for extended bottom-hole pressure buildup. Early data suggests this well is more productive and lower cost compared to the Company’s first two Utica wells. After the installation of the production facilities is complete, the well is expected to be brought back on line at a constant, constrained rate of production. Range has approximately 400,000 acres in southwest Pennsylvania which it considers prospective for Utica development. While results from the Company’s dry Utica wells are encouraging, Range will continue to focus capital on its prolific Marcellus acreage position that has been de-risked by thousands of wells, some with up to 10 years of production history.
Conference Call
During the company’s Q1 conference call, Jeff Ventura, CEO of Range, and other senior executives talked about the importance of the company’s marketing of ethane to INEOS in Norway.
“On the marketing side INEOS is now routinely picking up ethane at Marcus Hook and shipping it to Norway. At the same time we’re 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.
“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 a 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 costs. The capital efficiencies our team is achieving are very significant. This is particularly impactful when efficiencies are combined with the quality of the rock that 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 cost using current development cost to recover PUD reserves was $0.40 per Mcfe at year-end, 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.
“For the first quarter, we continue to drive down our overall unit cost, resulting in a reduction of 10% from the prior-year quarter. Basically all of the categories beat guidance.
“One particular item that I would like to call your attention to is 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.
“We’ve seen our water cost 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% production 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 cost 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 cost.
“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 outperformed 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 10 wells averaging 7,500 foot laterals completed with 39 stages. With nine of those 10 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 multiwell 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’s described — 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 onto a two-year-old Marcellus pad and drilled two new infill laterals between the existing laptops. 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 frac 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.
“The second example is in our dry area of Southwest Pennsylvania where we went back onto an existing three-well pad and drilled three new laterals. You can see this example on page 41. The original well had an average lateral length of 4,800 feet completed with a 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 from 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 in our wet area of Southwest Pennsylvania where we went back onto 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 per day equivalent per well. Five years later in 2015, we completed five new wells averaging [ph] 1,500 (15:56) 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 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 six to nine 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 cost as we develop new efficiencies, less gathering and compression as limited incremental infrastructure is needed when you’re on an existing pad, potentially improved performance as 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 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 begin 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 with $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 turned to sales five wells again which is illustrated on page 40, where we drilled on an existing pad. The new wells have a projected EUR of 3.6 Bcf equivalent per thousand 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 length. Ultimately, we expect that 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 HB 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 in 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 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 2017 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 ethane 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 netback pricing going forward.
“Looking ahead, our next transportation option coming into service is the Texas Eastern Gulf Markets 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 netback pricing.
“As a further update on our third Utica well, the DMC 10H is currently shut in for facilities build-out and an extended bottomhole pressure buildup. We expect to bring the well to sales in about 60 days. The just-over-30-day flowback 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 to date 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 the 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 wells while continuing to build our reservoir models and then determine the path forward from there.
“In the meantime, we’ll remain focused on our high-graded Marcellus core acreage with the best economics possible. As we continue to lower cost, improve efficiencies, drill longer laterals and develop our core assets, we remain well-positioned to create value.”
Conference Call Q&A
Q: 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 at $2 gas, that maybe a little premature or certainly irrelevant in this market. But just conceptually given the efficiencies that you’ve 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 over the longer term?
RRC: I think, let me talk about it in a very conceptual way and start with – 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 play area, by the end of this year it’s predominately 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 that a lot, our newest piece that’s in place, Mariner East. So the ability to move ethane, propane and natural gas really to multiple markets around the U.S. or even internationally, the ability to go back on existing pads, those are all key things. So, I think what you’ll see us do is we’re in a great shape in a low-price environment. We believe that a lot of good fundamentals are setting up for natural gas to improve rolling. We think this will be the first year natural gas supply rolls since 2005 or something back like that coupled with the time where demand is coming up. So when a lower for longer scenario, we’re well positioned, in a higher price scenario we have a lot of optionality. Ray has talked about 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 number of our drilling efficiency on 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 a lot of optionality to push the lever or the throttle forward or to pull it back, which I think is the position that we want to be in. So that’s kind of a longwinded answer, but I think philosophically, we will 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. Team continues to get better, better and better as evidenced by the capital efficiency and we’ve 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 away about some of those. I think when you look at them versus peers, they’re impressive numbers. So it’s – that’s kind of philosophically, how we look at it.
Q: I guess what I’m kind of struggling with is 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 train limits around that, whether it would be balance sheet or some kind of EBITDA coverage ratio or…?
RRC: Clearly balance sheet’s important, spending typically is going to be I think philosophically is going to be at or near cash flow but I’ll just basically leave it at that. Roger do you want to add on to that a little bit or?
Yeah. I think that 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. And I just don’t think it makes any sense to try and lock into a number right now, it’s too dynamic.
Q: 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 the better market or you thinking that’s something you might want to put your own capital to work in at some point?
RRC: Yeah. 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 and that from 200 wells, 200 old legacy vertical wells. You can do the math there.
So, the price that we got for that we thought it 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 play and there’s other plays, so we actually have eight rigs drilling in and around this. It’s all HBP, so our thoughts are to just wait, watch some of the drilling results that we expect will be good and then 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 by an – you can – but I think a map of our acreage was up on our website at one time, or the IR team will give it you. And somewhere you can look at the rig – the active rigs. I’m sure if you subscribe to those services, there’s a lot of activity around this. And this, the remaining stuff we have in the Panhandle and up in the Northern Oklahoma, I think you’ll just see us sell it 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, and 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 were very disciplined and we finally found a buyer that paid us what we thought was the price. I think if you look at both of those cases, the price we got was about double what most of the people thought that 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.
Q: Additional non-core sales, I mean, just kind of wonder 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?
RRC: A Major County package is probably marketable and we hate to always put timeframes on it, 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 there. It’s non-core to us. There’s other people that really like that area. Mississippian and again, and you can even we carved off Bradford County, so there 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.
Q: I was definitely intrigued by your comment that 50% plus of your well 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 or potential – I mean, it looks to me that it could be quite large.
RRC: Well, it’s a great question, and it’s more of a continual process. If you look at page 8 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 improvements and even across years where service costs were actually going up, we were making significant improvements. A lot of that’s driven b drilling longer laterals; it’s just a fact that our teams and our service crews are getting more and more experienced, and 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. I mean we’re really, really early in the planning cycle at this point. But some of the things that I talked about in my prepared remarks, and when you couple the savings with the fact that you don’t have build pads, and roads, and production facilities, other things that we don’t talk a lot about are things like surveying, 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. And all of those things could – you could save a couple hundred thousand dollars a well, 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 in my remarks. A couple of those 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 – when you roll all that together, the fact that we’ve got a great transportation portfolio, we’ve got diverse outlets for operational aspects as far – 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 operate and 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 fracs per day that we are or anywhere close. So I think there’s a lot of things out there like that that just give us a pretty unique advantage when you compare us to all our peers.
Q: I love that slide 15, with your gas in place. I know you and Bill were probably the first to ever put that out there. And I’m just wondering, number one, is that continuing to dead right here now for the last couple years on that. Two questions I guess around that is, 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 mean, I guess because of the pressure, it means 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 costs down on those dry Utica wells?
RRC: Two great questions. I think, the gas-in-place maps, 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 future – more and more development occur in the Utica and the Upper Devonian and then 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. And I think that’s a big reason behind our low base decline rate, is I think we have better hydrocarbon content – better perm, better porosity, better pressures. And 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, 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 a 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 our 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’ve talked about in my prepared remarks were 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.
Q: Thinking 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 $200,000 to $850,000 well savings you talk about.
RRC: 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 is the separators, the production tanks, the heater treaters and all those different things, they are going to be different in the superrich versus the wet versus the dry area. They are all different and I think people tend to want 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. And 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 costs, title, curative.
You’ve got a lot of different things like that that we don’t talk the whole lot about which are really significant. You’ve got water infrastructure. If it’s a well, 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 which that’s significant, when you’re drilling a new four well pad it’s really significant if you 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 just an existing pad, and there’s 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, those are – 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 are all different, but it could be – most of that cost goes away. Essentially, you are 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 then it’s just as far as LOEs and things, the way it helps you there is basically, you are not adding new equipment and new infrastructure that you have to add new lease operators for to cover. In other words, going back on the 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 kind of stuff that’s already there and being operated.
So, I don’t know that’s a long-winded roundabout way to kind of talk about some of those things, but all of that helps us reach the capital efficiencies that we’re with. And again, this has been a – this has been a process that we actually talked about in the very early days or way back to 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 wells, 15 wells, 18 wells in some 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 has been really a turning point year 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 these things have taken years to put in place, and I think that’s a very unique part of our story going forward.
Q: 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 priced 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’ll 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?
RRC: It’s really, it’s a great question, Dave. And it’s really all of that, plus I would add in there that it’s not always going to be going back on existing pads, because we have some, and 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 10 different wells from several different pads. When you look at that, the economics on that stuff is even if you build a new pad is probably better than going back on some of 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 gets us the best overall project return for our capital in a year’s time. Where are we going to be able to, just put $1 in where are we going to get the most dollars out. And it’s really that simple, but we have to factor in all of those things you talked about, where is markets, proximity to infrastructure, timing of sales that we’ve done with customers, all of those different things factor into that.
Q: Regarding your guidance on differentials in NGL pricing, what potential do you see for that to change either in the back part of this year or periods beyond that is, could we see narrower differentials on more gas leaving the basin in better NGL pricing on barrels being shipped than what’s guided?
RRC: I think if you look on slide 14 and it shows projected average differentials in 2016 versus 2017. So where we were expecting those differentials for the year to average $0.40 to $0.45 less than 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 moving Mariner East starting up and plus some of the early things where we now, we have kind of that optionality to either export or move into the U.S. 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.
Q: And then a follow up to that, just confirming that your guidance on transportation cost captures 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.
RRC: 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 in 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 $0.05 a gallon that’s on a $0.50 a gallon product that’s a big deal. We are 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 are hearing a lots of good things about the propane market and we’re hearing a 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 anyone particular project, we’re set up really well going forward.
RANGE RESOURCES Q1 2016 PRESS RELEASE HERE.
4.28.16 RRC Company Presentation – FINAL (1)
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