Range Resources issued its first quarter 2019 update earlier this week. Natural gas liquids (NGLs) were one of the themes of the update and analyst phone call–and no wonder why. The company produced an average of 2.26 billion cubic feet equivalent per day (Bcfe/d) of natural gas in 1Q19, nearly one-third (31%) of which was NGLs. Ethane and propane, getting them to market, is a major focus for Range.
CEO Jeff Ventura said in the update, “Range is off to a great start in 2019, exceeding production guidance for the first quarter and paying down $48 million in debt with organically-generated free cash flow.” Which helps explain why Range only made $1.4 million in net income during 1Q19, after they made $49 million in net income in 1Q18 (down 97%).
As for operational performance, Range “turned in line” (connected to sales) 23 Marcellus/Utica wells in 1Q19. They plan to drill and turn in line 88 wells in the M-U total for all of 2019, so that leaves 65 more wells to go for the balance of this year.
Range’s M-U production was 2.03 Bcfe/d in 1Q19. The rest of Range’s production (0.23 Bcfe/d) came from Range’s dalliance in the Louisiana Haynesville.
During the conference call held Tuesday Range officials expressed their joy (and relief) that Sunoco’s Mariner East 1 NGL pipeline is back up and running. Range was forced to find alternative ways to get their prolific NGL production to market while ME1 was down, since January 20. Range used other pipelines and railroads to get their NGLs to market.
The topic of divestitures came up on the conference call. It appears Range is shopping some of its M-U acreage and wells, particularly what they own in northeastern Pennsylvania.
During the conference call, Range’s senior VP of operations, Dennis Degner, had the following cryptic statement about a new butane export terminal along the East Coast:
During the first quarter, Range resumed its waterborne butane export program that began last year. This was enabled via the newly operational Mariner East 2 pipeline in associated infrastructure at Marcus Hook. Going forward, Range has also positioned a portion of its butane volumes for export using an additional East Coast terminal giving our products another outlet for accessing premium markets. (1)
Kallanish Energy picked up on Degner’s statement and had this observation:
Range Resources announced Tuesday it’s “positioned” a portion of its butane volumes for export from a new and unnamed East Coast liquids terminal, Kallanish Energy reports.
That will give butane “another outlet for accessing premium international markets,” Range said.
At present, Range and others ship liquids via the Mariner East 2 pipelines to Marcus Hook, Pennsylvania, for export. The new terminal was mentioned in one sentence in the company’s earnings report and no further details were provided.
Efforts to contact company officials for additional comment were unsuccessful.
It is possible that the new terminal could result from turning an existing faclity near Marcus Hook into a separate liquids hub. (2)
Hmmm, interesting. We’ll keep an eye out for this mysterious “new” butane export terminal.
As usual, Degner’s prepared statements on the conference call yielded a ton of useful information about Range’s drilling program in the M-U:
Our operating teams are off to a strong start for the year with first quarter production on track and capital spending projected at/or below our 2019 plan. First capital spend came in at $214 million or approximately 30% of our 2019 budget. Production for the quarter came in at 2.256 Bcf equivalent per day as a result of strong well results and incremental [indiscernible] quarter.
As we discussed on the prior call, our capital spending program is front-end loaded for the year. As we look forward and similar to past years, we expect our second and third quarter capital spending to each be approximately 25% of the annual budget this year. First, let’s talk about the well results. Similar to prior quarters, Q1 generated some exceptional well performance, which played a key role in exceeding guidance. One example is in our Appalachia dry gas acreage where we turned to sales 14 wells on two different pads. With average IP’s exceeding 30 million cubic feet per day from an average lateral length of over 13,000 feet. Both pads have produced at/or above 100 million cubic feet per day for 60 days and continue to produce at this level as of this morning.
On the other side of our acreage position in the last week of the quarter, we turned to sales three wells in the heart of our super-rich acreage. The average initial production from these wells was over 20 million cubic feet equivalent per day from an average lateral length of just under 7,000 feet. Despite the shorter lateral lengths on this pad, the first 3 wells produced peak condensate production that exceeded 3,000 barrels per day, solidly pointing to the quality of the acreage and results from the team’s technical work.
Flow back operations in this site will continue into the second quarter as we clean up the remaining four wells on the pad. We expect the performance of this pad and other near-term activity in the liquids-rich area to increase condensate production back to a level above 11,000 barrels per day during the second quarter. Now let’s look at field run time. For the past several years, our production team has conducted a thorough look back on the winter season with a focus on improving run time for the year ahead, especially the winter. This process, coupled with our ability to monitor production realtime has allowed the team to hone in our freeze prevention solutions such as heat trace and focus our lease operating team on sites requiring their support, ensuring production volumes flow as planned with downtime remaining low.
Similar to the team’s approach on 0 vapor protocol, this extensive effort between both the operations and technical teams translates into an improved run time and played a key role in our production performance in Q1. The first quarter closed out with 26 total wells turned in line, consisting of 20 wells in our dry acreage, 3 super-rich wells and 3 wells in North Louisiana. As we look ahead, we are setting our second quarter production guidance at 2.27 to 2.2 Bcf equivalent per day, which aligns with our 2019 production plan to deliver approximately 6% production growth, while delivering meaningful free cash flow within our capital budget of $756 million.
Now let’s turn to some of the team’s operational highlights. The past year has showcased several accomplishments by the Appalachia drilling team as they drilled our longest, fastest and most capital-efficient wells. The team’s first quarter results continued this trend as they successfully drilled 3 of Range’s Top 5 longest Marcellus laterals with all 3 laterals exceeding 18,000 feet. As discussed on prior calls, Range has been able to reduce drilling cost per foot during extended lateral operations by as much as 30%, a contributing factor to our underspend last year and an important component in allowing us to deliver on this year’s financial objectives as we deliver peer-leading normalized well cost. We look forward to sharing the production results from these long laterals in the upcoming quarters.
On the completion front, the team pumped over 1,300 frac stages in the quarter, while seeing a 20% efficiency increase in frac stages per day compared to the same time just 1 year ago. Both operational accomplishments point to the quality of our team, coupled with the strength of our service partner relationships, especially considering this was accomplished during winter conditions.
As Jeff mentioned earlier, water recycling continues to play a significant role in our sustainability efforts as we execute on our 2019 program as efficiently as possible. You’ve heard us talk about how we recycle 100% of Range’s water in Southwest Pennsylvania. But through the team’s creative efforts, we have partnered with other operators to recycle their produced waters as well. In the first quarter, third-party water comprised over 20% of our water usage.
Range’s water management program not only contributed to an efficient first quarter capital spend, but it also contributed to Range’s first quarter corporate LOE of $0.16 per Mcfe, which is approximately 16% below our LOE when compared to the same time last year. I think this is a great example of the team working tirelessly to find the next incremental step and efficiency gains, cost reduction and overall improved program results, and it’s a great example of the team working collaboratively with other operators to be thoughtful stewards of the environment and pushing the standards for the industry.
Shifting over to our liquids marketing efforts. As we’ve shared on a prior call, the Mariner East 1 pipeline was temporarily taken out of service in late January, following a subsidence appearance along the pipeline route. Since that time, the marketing team has worked diligently pursuing options to secure our production flows. For propane, we have utilized available capacity on Mariner East 2 and other outlets to move our barrels to the Marcus Hook terminal and other markets.
In the case of ethane, we have utilized various options for marketing our production to the quarter, including both normal extraction and selling ethane as natural gas. Overall, despite the temporary disruption on the Mariner East I pipeline, Range has successfully engaged transportation and market alternatives to keep its natural gas liquids otherwise transported on ME1 flowing to both domestic and international markets through the utilization of rail and other infrastructure in the region. Based upon the latest update from Energy Transfer, start-up procedures are underway with the Mariner East I pipeline returning to service over the balance of the next few days.
During the first quarter, Range resumed its waterborne butane export program that began last year. This was enabled via the newly operational Mariner East 2 pipeline in associated infrastructure at Marcus Hook. Going forward, Range has also positioned a portion of its butane volumes for export using an additional East Coast terminal giving our products another outlet for accessing premium markets.
Including hedges, Range’s first quarter NGL realization was $23.17 per barrel, an increase of 15% year-over-year. Based on recent strip pricing, Range expects pre-hedge NGL pricing for 2019 to average 34% to 38% of WTI. On an absolute basis, expected realizations are now slightly better than our original 2019 pricing guidance of February.
There has been some market confusion around NGL prices recently, so I want to repeat that, while the relationship to oil prices temporarily weakened, our forward strip based on NGL price per barrel expectations are now slightly higher than when we had our year-end earnings call. Propane and heavier products, which represent over 75% of the NGL barrel’s value continue to be well supported by international export demand.
Currently, U.S. export terminal capacity is tight and the U.S. propane and butane market is seeing the strongest international export orders in the past 5 years with prompt spot cargoes loading at over $0.10 per gallon net of shipping costs. We expect this to cause max possible export of NGL products over the course of 2019 and ultimately support Range’s decision to gain access to Marcus Hook or other East Coast export capabilities in the future.
On the gas marketing side, the first quarter saw the full utilization of the recently commissioned Mark West Harmon Creek I gas processing plant. This facility, along with the restart of the Houston gas processing plant following fourth quarter outages saw strong run times for the first quarter and supported processing for first quarter wells focused in our liquids-rich acreage. As discussed on the prior call, the new plan allows us to maximize the utilization of newly available long-haul infrastructure.
With a significant amount of downstream takeaway capacity that has come online over the last couple of years, local Appalachia pricing has improved. Additionally, with the slowdown in Southwest Pennsylvania production growth for the industry, we believe this local pricing trend will continue.
Further, with the combination of additional downstream takeaway capacity and local generation demand growth, we expect this will provide additional in-basin liquidity and market growth opportunities with less transportation cost associated with incremental natural gas production.
Range remains actively engaged in developing in-basin markets and optimizing our infrastructure to existing in-basin points of liquidity. Evidence of the team’s work in optimizing the portfolio can be found in the $6 million net gain from the brokered gas marketing activities in the quarter.
I’ll close out the operation section with this. The team has done a great job with our first quarter results, highlighting exceptional well performance, capital discipline and operational efficiencies from long lateral development. This really helps set the stage for delivering on our capital budget and production targets in the year ahead. (1)
A question came up during the Q&A portion of the conference call about NGLs and where prices are heading over the next year or so. It was an enlightening answer from Range’s VP of liquids marketing, Alan Engberg:
Ronald Mills
Dennis, you referenced NGL prices and I know relative, given the move up in WTI, it looks like you brought down the low end of the range, but your comments are pretty telling that even when using the strip, the absolute prices are higher than — are actually looking for trend higher. Any additional color, whether it is about strip or your thoughts on NGL markets as we look through the rest of the year, particularly fourth quarter when the seasonality starts to benefit NGLs even more?
Alan Engberg
Ron, thank for the question. This is Alan Engberg, I’m the Vice President of our Liquids Marketing team. So I’ll see if I can give you some color around liquids. Absolute prices are actually similar to what we guided back in February, there are up for the quarter actually, roughly about $3 per barrel. Now as you know and as you pointed out, crude is up quite a bit more. Crude is up about $15 a barrel for the quarter. Typically, NGLs will always lag crude on the way up and on the way down. However, this quarter there are a couple of one-off events that caused it lag more than usual. So if I start with LPG or starting with propane and butane. Exports, in particular, were one of the big drivers. They were negatively impacted by an unusual amount of fog this year along with Houston Ship Channel. Added to that, there was a big fire at ITC’s tank farm that caused contamination of the water way and that further slowed down all traffic on the Houston Ship Channel. And by our estimates, there was approximately 20,000 barrels per day that were impacted over a 45-day period. So 9 million barrels that didn’t ship. So that was just a big kind of change to the market that the market wasn’t expecting.
And note that the rest of the world has really come to depend on U.S. exports, and those delays actually caused a spike in overseas prices, both in Europe and in Asia, that have resulted in — right know, what we’re seeing is the highest LPG arms in roughly 4 years. Going forward, we expect things improve. This was a one-off event, it’s over with. The ship channel is pretty much cleared. But on top of that, we’ve got new export capacity coming on. So as we mentioned in the call, ME 1 is backup but also up in the Northeast, you have ME 2 running, and that’s transporting roughly 150,000 to 165,000 barrels per day to Marcus Hook for export. Last year at this time, those barrels were going into local storage. This year, they’re going overseas. So it’s a big impact of supply/demand balance up in the Northeast.
Shifting down to the U.S. Gulf, Targa is debottlenecking their capacity, most of that will be next year but some of that has actually already happened. They’ve added a butane pipeline that adds roughly 30-a-day of new capacity. And then Enterprise is debottlenecking their capacity, they’re adding 175,000 barrels per day with new export capacity. That will be starting up in the third quarter. So if you add up just that new export capacity, we’ve got 355,000 barrels per day that’s going to be going into international markets that are actually hungry for the product. And for just for reference, 355,000 barrels per day, U.S. produces gas plant production of propane and butane is roughly 2.2 million barrels per day. I’m just citing EIA data for the most recent month that was published, which is January of ’19. So 355,000 out of 2.2 million a day is 16% of supply that’s going to be additional increment that’s going to be going offshore. So for those reasons, we expect things to improve as we continue on through the year.
For ethane, things were a little bit different there. We had ethane prices come off during the second half of the first quarter. A big part of it is a story that we are already familiar with, there’s this big new crackers coming online that have been delayed. So they were delays from last year, and then in the first quarter, we learned leaned of further delays. So we have 5 new crackers that are coming on but they’re coming on later in quarter, sorry, later in this year. The fog also impacted ethane — ethylene prices. So ethane is the main feedstock for making ethylene. Ethylene prices dropped down quite a bit down to $0.13 per pound, that put some pressure on ethane prices.
On top of that on supply-side, cooler weather allowed more pipeline flow from various locations to Mont Belvieu. It also allowed more fractionation capacity. We’ve got a little bit of new infrastructure, new pipeline came on in February, Chinook’s pipeline from the Permian and Lone Star added new fractionator. And then finally, on the Permian, natural gas has been painful to watch. Actually, we’ve had WAHA index trading at negative values. And when it’s trading at negative values, the Permian producers have every incentive to recover as much ethane as the pipelines can take. So we’ve seen that happening as well. But going forward, on ethane, the story does improve there as well. So out of those 5 new crackers, 2 of them are starting as we speak, and then that’s roughly 90,000 or — sorry, yes 90,000 barrels per day. And then we’ve got the other 3 are starting during the third quarter, and that will add 215,000 barrels per day of demand. Added to that, there will be more ethane exports with ME1 backup as well as some of the capacity that’s freed up on ME1 due to ME2 starting up, there’ll be more ethane moving on that pipeline.
And then our friends at INEOS actually are bringing online a new VLEC. It will be the world’s largest ethane carrier. It’s actually moving towards the Houston ship channel now. That thing will be able to hold 850,000 barrels per load, and that will add roughly 15,000 barrels per day of demand, that product will be going to new steam cracker that’s starting up in China later on this year. So overall, with roughly 320,000 barrels a day of new ethane demand coming on during the next 3 to 4 months, we expect to see some improvements in ethane prices, and for the reasons I mentioned earlier in propane and butane prices. (1)
A question to Dennis about long laterals:
Brian Singer
You mentioned that your ability to continue to push out lateral lengths with some of the 18,000 feet lateral test, can you remind us year base expectations for how you see well cost per foot, and EURs per foot evolving? And then how long do you think you can push out those laterals until you would either see sufficient operational risk or acreage limitations?
Dennis Degner
Brian, at this point, we’re really confident in the 18,000-foot lateral length that we’ve been able to drill. I think on the prior call, we referenced that we certainly had a substantial number of laterals that were in excess of 15,000 feet. When you look at — and we’ve been able to do this across as we think about our acreage position, both in the core of Washington County where we had historical wells, but we’ve also been able to do it in areas where maybe we have a cleaner sheet of paper in fewer wells that we’re drilling around. So by having a blocky acreage position, the way we do and it being continuous, it really affords us an opportunity, coupled with the gathering system to really — to maximize that lateral length opportunity. We’ve typically been a incrementing type operating team. So rarely will you see us go from 5,000 feet to say 20,000 feet in any kind of operation because we understand that we want to manage the risk. And part of being us — part of us being successful in an unconventional resource play is being repeatable.
So getting to the 18,000 feet point that we’ve gotten today, we really like the results we’re seeing. As we look back on the performance of these wells, I’ll shift there for a quick second. The wells that we reported toward the end of last year that we drilled. One, it was at 17,800, and the other one as at 18,100, both of those wells are at/or above the type curve, super rich type curve still today. We looked at those results just over the last few days. So we really like what we see on a normalized basis out of the wells. The drilling team continues to push down cost per foot. We’ve seen, as we’ve mentioned earlier, as much as a 30% increase. So we really like the direction we’re headed. Average drilling length this year, I believe we reported was going to be about 13,000 feet for the program. But when you look at a lot of our references, it’s not uncommon again for us to point to 10,000 feet, we feel like that’s a good spot as well, but we will have those cases like a few of the super-rich wells we’ve pointed out that IP’ed at 7,000 feet, so we will have some filling space. But our goal will always be to maximize on the lateral length because we see that is the most capital-efficient approach. (1)
As for talk about divesting some assets, including Marcellus assets in northeastern PA:
Rehan Rashid
Two quick questions. One, the 20% improvement in frac efficiency I think that was mentioned earlier, kind of what changed and kind of how does that drive CapEx per well? If I could get some color on that, that’s one? And two, maybe a little bit more color around kind of the divestiture timeline and any particular area that’s focus in terms of divesting?
Dennis Degner
Thanks for joining us on the call this morning. I’ll start with the frac efficiencies and hand over to Mark. On the frac efficiencies, we had exactly quantified how all that savings will be translated into our cost per foot as of this morning, but we know that as you look between winter and I’ll just say, non-winter operations, they’re substantial savings and mainly because of some of the supporting hardware that goes along with our operations during the winter, whether it’s supporting equipment, et cetera. When you look at our cost of completing and drilling wells, what we see is that over the balance of time, it translates into reduced cost per foot for us. So when you look a year ago, efficiencies were starting to kind of stabilize at that point. This year, we’re seeing through the balance of continuous operations with some of our crews and also increase in our knowledge base on location, we’re seeing that performance translate into it really improved performance on location. So really like what we see and expect that this should continue throughout the balance of the year. Now, with some seasonal differences, you might see little bit of a fluctuation, but the crews have performed extremely well, pointing back to our service partner relationships.
Mark Scucchi
This is Mark. On the divestiture front, as we’ve talked about before, we have a number of processes underway. And again, there are in various stages from negotiations, there’s the data rooms to diligence with a variety of efforts underway. We’re not good to pin down the timing, but what I can point to is a few facts that hopefully gives us some comfort and some guidance into what we’re striving to achieve. So obviously, we were successful last year in closing on the royalty sale and closing October of last year. We will consider royalties again, we’ve mentioned northeast PA, we mentioned noncore acreage as potential candidates, all those dialogues are ongoing. Another read on the sense of urgency, not just kind of our alignment of interest but the importance of the factor as well as the timing is the addition of an absolute debt-reduction target in the management performance measurements and incentive program as you can see in the proxy. So there are specific targets there for us to strive to achieve at the high end to maximize that metric, that would be a $700 million reduction in debt for 2019. So while we’re not going to give specific guidance on timing or dollar amounts of specific transactions, those are in broad strokes how we’re thinking about it and what we’re striving to achieve.
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Brian Singer
Great. And then to follow up on the divestiture question. Given that this has been an area of focus for some time, can you just broadly discuss how the market environment and marketing interest in Appalachia upstream assets either directly or via royalty compares today relative to 12 to 18 months ago?
Dennis Degner
Sure. So I’d say, depending on area, the evolution of investor interest and the bid-ask spread has evolved. So for example, in North East Pennsylvania with Atlantic Sunrise coming online, seeing actual sales curve, basis tightening, not just in the forward curves but in the spot market and the actual physical transactions, that gives potential buyers greater confidence in the economics that they’re forecasting. So that I would say is an improvement. The variety of interested parties and types of investors remains pretty diverse and strong, there are multiple potential parties in each data room. In Southwest Pennsylvania, I would say that those discussions continue to evolve. Just as an example, after we announced last fall successful Royalty sale, we actually received several inbound phone calls of party saying, “Hey, I wish we had known that, that something that you would consider.” So in general, I would say that the A&D market is alive and functioning. (1)
Copy of the full Range Resources 1Q19 update:
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Copy of the latest Range slide deck:
Range Company Presentation – April 22, 2019_
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(1) Seeking Alpha (Apr 23, 2019) – Range Resources Corp (RRC) CEO Jeffrey Ventura on Q1 2019 Results – Earnings Call Transcript
(2) Kallanish Energy (Apr 24, 2019) – Range hints at new East Coast liquids terminal for exports
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