Range Resources, the very first company to sink a Marcellus well back in 2004, issued its fourth quarter and full year 2018 update yesterday. Range’s overall production increased 5% year over year, but production in 4Q18 actually fell from 4Q17 in part due to an explosion and extended processing plant outage at MarkWest’s Harmon Creek operation.
Range’s 4Q18 production was 2.149 Bcfe/d, down from 2.170 Bcfe/d in 4Q17, mainly due to lower volumes in Range’s Louisiana shale program.
However, Range could have produced more had it not been for an explosion at the MarkWest Houston facility in December, which knocked production offline for roughly five days (see MarkWest Plant Explosion in Washington Co. Injures 4; 1 Critical). Range said the “extended curtailment of both processing complexes” caused them to lose 10 Bcf of production. Ouch.
Northeast Marcellus production averaged 113 net million cubic feet equivalent per day (MMcfe/d) during 4Q18, while the southwest Marcellus production averaged 1,780 net MMcfe/d during the quarter, a 7% increase over the prior year (even with the MarkWest outage).
Range reported a net loss of $1.75 billion in 2018 after making a $333 million profit in 2017. However, almost all of the “loss” was a paper loss. In 2016 Range bought Memorial Resource Development and its 220,000 acres in the Terryville Field in northern Louisiana for $4.4 billion (see Range Resources Completes Buyout/Merger with Memorial Resource). The Louisiana wells haven’t performed as expected, and so the value of that asset has plummeted. Range paid $4.4 billion, but “wrote off” (devalued) $1.6 billion of it in 2018, meaning the Louisiana assets are now worth $2.8 billion. Ouch. The company wrote off another $515 million in “unproved properties.”
In 2018, Range brought 86 wells online into production in the Marcellus, and 12 online in Louisiana, with an average lateral length of 9,388 feet.
For 2019, the company plans to drill and bring 88 wells online in the Marcellus, and 8 in Louisiana with an average lateral length of 10,800 feet.
Similar to the 2018 program, approximately half of the 2019 Marcellus wells are planned to be drilled from existing pads.
Range said they will spend $154 million less on drilling in 2019, budgeting $756 million, down from $910 million spent in 2018.
Here’s the official Range 2018 update with financials:
Dennis Denger is Range’s SVP of Operations and the wizard behind their drilling program. Here’s Dennis’ prepared remarks made on the earnings call with analysts:
Thank you, Jeff. Production for the fourth quarter came in at 2,149 million cubic feet equivalent per day. This contributed to an annual 2018 production number that was approximately 10% year-over-year growth and includes the impact of both the mid-continent asset sale and the override interest sale during the year.
As previously disclosed, fourth quarter production was materially impacted by an unfortunate incident at MarkWest Houston processing facility. Throughout the ensuing outage, Range’s Southwest Pennsylvania volumes were curtailed while necessary repairs could be made, resulting in an approximate 10 Bcf equivalent reduction in production for the quarter, the majority of which occurred during the month of December. Repairs to the MarkWest facility have since been completed with full operations restored during the first week of January. As Jeff mentioned, capital spending for 2018 came in $31 million below our original guidance set at the beginning of last year, resulting in a total spend of $910 million. We’re proud of the team’s dedication to safe, efficient operations and capital discipline that led the spending below our plan budget. I’ll go into more details on some of the achievements that led to this in a minute, but the board takeaway is simple: We expect capital spending at or below budget to be the rule, not the exception.
As we look forward, our 2019 capital budget is set at $756 million, with 90% allocated to the Appalachian-Marcellus program and 10% to North Louisiana. We expect this to generate year-over-year production growth of approximately 6%, including a 30% liquids contribution, while generating an excess of $100 million in free cash flow. We earmarked 93% of the capital to be directed towards drilling completions, facilities and pipeline infrastructure, which is a slight increase compared to last year’s budget and helps to improve capital efficiency per unit of production. The program will consist of 96 wells being turned to sales during the year. In Appalachia, liquids-rich wells will comprise of approximately 60% of the expected activity. And similar to 2018, up to 50% of the wells turned to sales are expected to be from pad sites with existing production.
Average lateral lengths per well are projected to increase this year with turn-in-lines averaging approximately 10,500 feet, while the average drilled horizontal lengths will increase to over 12,500 feet, a year-over-year increase of 1,600 feet and 2,500 feet, respectively. We see this plan setting us up well for 2020 and in line with the path ahead illustrated in our five year outlook. Similar to 2018, our 2019 capital spending is expected to be weighted to the first half of the year with approximately 35% of the capital being spent in the first quarter and sequential production growth projected to throughout the year.
Honing in on the fourth quarter, the Appalachian team remained operationally focused and turned to sales 16 wells in the liquids acreage, taking the 2018 total to 86 Marcellus turn-in-lines. Similar to our last discussion on the prior call, this total is slightly lower than the original number of wells planned to turn-in-line for the year. The 2 drivers for these were 7 wells that were completed in the fourth quarter with first sales pushing into early Q1 along with extending lateral lengths on wells throughout the year. In any given year, we will aim to turn-in-line the budgeted lateral footage with fewer wells and longer laterals to maximize efficiencies.
In North Louisiana, we completed and turned to sales one well during the quarter. In 2018, the North Louisiana team’s charge was straightforward: drill our best picks, evaluate the impact of the structure and completion design and lastly, deliver on production targets within the capital budget. Looking back on the year, we’ve enhanced our understanding of structural influence in the area and have seen benefits from an increased completion design. When evaluating the wells from last year, the average production is in line with our expectations but not where they need to be on the competitive return spaces. The early part of 2019 will be key as the team test the latest structural aspects for the Cotton Valley and will assist in determining the asset’s overall direction going forward.
Now let’s look back on some of the key achievements for the year that drove our capital underspend. A key theme for Range in 2018 was our ability to drill long laterals in the Marcellus, resulting in a lower cost per foot. The Southwest Pennsylvania team was able to increase the average lateral length drilled by 8% in 2018 while drilling the longest Marcellus well at 18,600 feet. Along with the drilling three more of the basin’s top longest laterals to date.
In addition to drilling our longest laterals, we also saw our drilling efficiencies continue to improve. The drilling team was able to increase footage drilled per rig by 20% versus 2017. And with these efficiency gains, along with 18 wells successfully drilled beyond 15,000 feet, the team has been able to reduce the drilling cost per foot during extended lateral operations by as much as 30%, a key component when looking at our capital underspend and in improving our overall capital efficiency.
Water recycling also continues to play a significant role in our program, and 2018 was no exception. By recycling 100% of Range’s water in Southwest PA, the team played a large role in achieving our corporate LOE of $0.17 per Mcfe for the year. And by taking third-party water, they reduced the per stage water costs by 10%, resulting in one of the largest drivers in our capital underspend. These are just two examples of where the team’s creative efforts, combined with our high-quality asset and contiguous acreage position, have strongly impacted the program efficiency.
On the marketing side, fourth quarter marked the first full quarter where Range had access to all of its contracted natural gas transportation, as Energy Transfer’s Rover project provided additional outlets to the Midwest and Gulf Coast in September. The quarter also saw the commissioning of MarkWest’s Harmon Creek 1 processing plant, which reached full capacity in early December. As we discussed on the prior call, fourth quarter wells were focused in our liquids-rich acreage near this new processing plant, allowing us to maximize utilization of this newly available infrastructure.
The fourth quarter natural gas differential of $0.08 under NYMEX was the best Q4 differential Range has seen since 2012, due in large part to the addition of transportation out of Appalachia. Going back a few years to the 2013 to 2014 timeframe, the Appalachia basin took on significant commitments to have natural gas transport built to the Midwest, Gulf Coast and Southeast, enabling the current market environment of improved basis.
It seems to have been a long time coming with various pipeline delays but overall, it ended up aligning perfectly with Range’s revised production profile. Compared to our original 2014 plans, we reduced our production trajectory and corresponding capital spend, but we’re able to fully utilize each firm transport project shortly after its in-service date. Range’s early strategy of creating a diversified market portfolio, inclusive of in-basin exposure, has been and is expected to continue to be beneficial to realize natural gas pricing and managing cost structure. To that end, going forward, Range expects to keep its natural gas transportation full and sell incremental gas production in the local markets, which have improved as infrastructure has been built out in the Southwest part of Appalachia.
On the liquid side of the marketing, as the only producer with propane capacity on Sunoco’s Mariner East I, Range has been able to capture premiums to the Mont Belvieu index price by exporting the majority of its propane to international markets since early 2016. In addition, the company sent the majority of its normal butane and remaining propane volumes during the summer to Marcus Hook for export via local rail. The majority of those same volumes are being sold locally during the winter months. In total, Range markets over 70% of its corporate NGL production each quarter.
As we continue to develop our liquids acreage, additional outlets for NGL production are beneficial in providing stability to NGL price, especially during the summer when in-basin demand is low. Given the added purity volumes that could be supplied to Mont Belvieu over the coming years, we believe additional exposure to international NGL prices are warranted. As a result, Range has taken capacity on Mariner East 2 for a combined 20,000 barrels per day of propane and butane starting in April 2020. Importantly, we have the ability to fill that capacity with propane and butane volumes we produce today, leaving flexibility to sell incremental NGLs in-basin on a go-forward basis.
In January, we lost access to capacity on the Mariner East I pipeline, following the appearance of a subsidence along the pipeline route. As a result of the outage, we are utilizing available capacity on Mariner East 2 to continue moving propane to the Marcus Hook terminal. For ethane, we have multiple options for marketing production, including the ability to sell ethane as natural gas. While not materially altering corporate cash flows, the delayed restart of MarkWest plants and the Mariner East outage have reduced production volumes. And as a result, Range’s first quarter guidance of 2,225 million cubic feet equivalent per day reflect the estimated production impact.
Before handing over to Mark, I’ll close out with this: We’re extremely proud of the team’s accomplishments in 2018 and are excited about what’s in-store for 2019, as we continue to deliver on the capital budget and our production targets while we drill and produce our most cost-effective and operationally efficient wells.*
During the Q&A, we spotted this interesting exchange about the Mariner East pipelines and their impact on Range and what Range expects in 2019 (Jeff Ventura is CEO of Range):
I was wondering if you could help us understand, on the Mariner East 1 outages, maybe the operating and financial impact in 1Q and 2Q and thoughts on when capacity would be restored.
Yes, this is Dennis. At this point, it’s still a little unclear on when the operations will be restored on that particular line. We remain in close contact, as you would imagine, with the folks at Energy Transfer around operational status of that line. The good news is, is we have optionality. We have other outlets that we use on regular basis to basically transport our ethane to other markets. We continue to look at those options through the first quarter to both capitalize on pricing environments but also minimize impact when it makes most sense, so we’ll continue to do that through the first quarter. From a financial and production aspect, I don’t think we have something that we’re prepared to share at this particular point other than the guidance that we’ve shared here in the call today. We feel like we’re on track with the 2,225, and it also puts us in line with our growth profile of 6% for the year.
Okay. And just the cost and the capacity, you have capacity on Mariner East 2. Could you maybe discuss that cost?
That’s the kind of detail that we’ve not typically provided, whether it’s Apex or Mariner East I or Mariner West. But, Alan, perhaps you can talk about the strategy behind taking ME2 capacity?
Sure. And I’ll point out this, there’s published tariff rates on the pipeline, so it’s available on the Internet. People can look that up, but the details of our own deal is, as Laith was just saying, are confidential. Overall, though, the reasons for taking on ME2 capacity, the Northeast market is — it’s a great market, it’s very seasonal. It has wonderful winter demand. But unfortunately, in the summertime, there is not a preponderance of local demand. And to make it a little bit more challenging, actually, there’s not much storage in the local area. So kind of like our strategy in natural gas, if we’re marketing our products directly, we like to build up as much optionality in our portfolio as we can so that we can get to diverse customers and industries with our product and realize the best overall prices. So what we’ve taken out of actually is 20,000 barrels per day on ME2 starting next year, and we’ll actually be able to fill that volume with existing capacity and we’ll have optionality on the remainder of our capacity to continue to sell to local markets or actually to put it on lockup space, let’s say, on ME2. So the ME2 capacity, again, as we see it, it provides a good option for the summer markets and actually provides a price forward to enter markets. It’s all the way around. It’s a good thing to have.
Arun, I might add that the cost of the ME2 is embedded in the cost guidance that we provided in the five year outlook when you see the step down from 4Q ’18 to 4Q ’19 and then a further step down in the five year outlook, and it’s also in embedded in the pricing guidance that we provided that shows about 40% of WTI in the years 2020 through ’23.*
*Seeking Alpha (Feb 26, 2019) – Range Resources Corp (RRC) CEO Jeffrey Ventura on Q4 2018 Results – Earnings Call Transcript
Copy of Range’s latest slide deck, used during the earnings call:
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