Antero Resources Corporation (ticker: AR) reports record gas production; Chesapeake Energy Corporation (ticker: CHK) produces 30 MMcf/day with new Marcellus wells; Gulfport Energy Corporation (ticker: GPOR) leads with planned $1 billion CapEx
Antero Resources Corporation (ticker: AR)
Production and financial highlights
- Net daily gas equivalent production averaged a record 2,317 MMcfe/d, a 24% increase over the prior year quarter
- Record liquids production of 112,393 BBLPD, a 38% increase over the prior year quarter
- Liquids revenue of $251 million, comprising 38% of total product revenues
- GAAP net loss of $135 million, or ($0.43) per share
- Adjusted EBITDAX of $336 million
- Successfully monetized over $1 billion of non-E&P assets through combination of the sale of Antero Midstream common units and the restructuring of the hedge portfolio
- Entered into a new upstream credit facility with a borrowing base of $4.5 billion and lender commitments of $2.5 billion
Antero Resources Corporation Chairman and CEO Paul Rady said, “Through increased EURs and lower well costs, we have been able to reduce our drilling and completion capital spending plans over the 2018 through 2020 period by approximately $1.5 billion while delivering the same production growth.”
Marcellus Shale highlights
- Completed and placed on line 31 horizontal Marcellus wells with an average lateral length of 9,500 feet, 25 have been on line for more than 30 days and had an average 30-day rate on choke of 17 MMcfe/d (17% liquids), assuming 25% ethane recovery
- Drilled an average of 4,884 lateral feet per day, which represents a 42% increase compared to 2016
- Current average well costs are $0.91 million per 1,000 feet of lateral in the Marcellus assuming a 2,000 pounds of proppant per foot completion
- Average drilling days from spud to final rig release was 12 days, a 20% reduction from 2016
- Currently operating five drilling rigs and three completion crews in the Marcellus
- In early July 2017, Antero drilled its longest laterals to date in the Marcellus, with three laterals averaging 14,000 feet. These wells are expected to be completed Q4 2017 and placed to sales in Q1 2018
- Completed a four-well pad using 2,500 pounds of proppant per foot and with an average lateral of 11,100 feet, that had a 90-day rate of 20 MMcfe/d per well
Ohio Utica Shale highlights
- Completed and placed on line six horizontal Utica wells with an average lateral length of approximately 9,600 feet
- Antero drilled four 17,000′ laterals and set a record for drilling its longest lateral to date at 17,445 feet. This lateral was drilled within a 7 foot target zone and was drilled in five days. The wells are expected to be placed to sales in Q2 2018
- Current average well costs are $0.99 million per 1,000 feet of lateral in the Ohio Utica, assuming a 2,000 pounds of proppant per foot completion
- Antero is currently operating one drilling rig and one completion crew in the Utica Shale
- Upon Rover phase 1B being placed in service, Antero expects to turn in line two dry focused Ohio Utica pads that total ten wells
Antero conference call Q&A
Q: My question is about the C3+ proportion of total NGL barrels, how do you see that changing in 2018, if at all from 2017?
Antero Chairman and CEO Paul Rady: I think it’s going to be roughly the same proportion or maybe even climbing a little bit on C3+. If we’re recovering roughly 30,000 barrels a day now, we may step it up to as high as 40,000 barrels a day, but the C3+ proportion will grow a little bit above that proportion of 30 out of 150.
Q: You were active earlier in the year and last year on acreage acquisitions, over 110,000 or 115,000 acres. Will you continue to look at that, or now with the large inventory you have, will that die down a little bit?
Antero: It’ll die down a little bit. We continue to add around the edges and any tracks that we have big tracks in the middle of our acreage block. But a lot of what we’re doing is now just getting the last few percent in each of our drill site units. We’re at, quite often, a 100% working interest. So today, we might be with locations that are on the book at 95% or so, and a lot of that is just the final stages of filling in.
Q: Your base plan through 2020 is assuming $54 oil. So, if we have higher oil prices or higher NGL realizations, then in your base case plan, what do you do with incremental cash?
Antero: Just going up towards $60 a barrel generates quite a bit more free cash flow. We positioned the company strategically to be more focused on holding 44% of future drilling locations in the liquids rich areas of the Utica and the Marcellus. We’ve done a lot of work on that over time just understanding where the remaining locations and what companies hold them, and we’re highly confident in our position.
Chesapeake Energy Corporation (ticker: CHK)
Production and operation highlights
CHK Q3 Total Production
- Total production reached approximately 584,000 Boe per day, including 99,000 barrels of oil
- Currently utilizing 14 drilling rigs across its operating areas, five of which are located in the Eagle Ford Shale, three in the Powder River Basin (PRB), three in the Haynesville Shale, two in Northeast Appalachia, and one in the Mid-Continent area. Chesapeake plans to average 14 rigs in Q4.
- Chesapeake expects to place on production up to 73 wells in the Eagle Ford in Q4
- Adding a third rig in the PRB, Chesapeake expects to place on production up to 11 wells in Q4
- In the Utica Shale, enhanced completions techniques have yielded an approximately 25% improvement in 120-day cumulative production
- In the Haynesville Shale, Chesapeake turned 12 wells on production in Q3, averaging lateral lengths of 8,440 feet and initial production of 31,840 Mcf of gas per day
- In the Mid-Continent, Chesapeake recently drilled and completed a 10,000-foot lateral well with an enhanced completion design on the Bravo 1H well in Major County, yielding an average production rate of approximately 1,550 BBLS of oil per day and an average total production rate of 1,960 Boe per day over the first 10 days.
Chesapeake Energy Corporation CEO Doug Lawler said, “We are pleased to announce the results of two new wells with enhanced completions in the Upper Marcellus that are producing at rates of approximately 30 million cubic feet of gas per day.”
Financial highlights
- Net loss to common stockholders of $41 million, or ($0.05) per diluted share
- Adjusted net income attributable to Chesapeake was $106 million, or $0.12 per diluted share
- Total capital investments were approximately $692 million
- Current guidance range for total capital investments was raised to $2.3 to $2.5 billion, from $2.1 to $2.5 billion
- Principal debt balance was approximately $9.8 billion
CHK CapEx
Chesapeake conference call Q&A
Q: What about your divestitures? Can you talk more about that?
Chesapeake Energy Corporation CFO Domenic J. Dell’Osso: We have always considered asset sales in three buckets. There are truly non-core assets, which this company and every well-run E&P company should sell every year. There are assets that we own a significant position in where we can trim a bit of our position, and still own a good solid position going forward but accelerate value from a part of the play that we wouldn’t get to in a reasonable period of time.
We work all three of those buckets of asset sales every day. Transactions through the middle of 2017 have been challenging. The availability of capital to this industry has been limited, while the broad capital markets across all industries have been very strong, and there have been brief windows where we and others have been able to access the high-yield capital markets and other forms of capital successfully. Broad-based access to capital for growth has been limited.
What that results in is a difficulty to bring transactions to fruition, but there are many motivated buyers out there seeking that capital, and we’re talking to many of them, and we will remain laser-focused on delivering on our asset sales to reduce our debt. We’ll stay away from deadlines that are ultimately somewhat artificial, whether they’d be at the end of this year or the beginning of next year. We’ll get that done. We’ll get it done at the right time for the right value.
Q: You mentioned your success with a couple of Austin Chalk wells in South Texas, what are you guys seeing with your most recent wells and how does that play into 2018?
Chesapeake Energy Corporation VP of E&P Frank J. Patterson: We haven’t talked much about the Austin Chalk. We’ve had the wells on for a couple of months. We went out and took all the industry data that we have seen in the play. The data covers the southwest portion of our acreage and so we designed a program just to test the concept. Then we drilled the wells and put relatively large fracs on them.
It took a while for the wells to come back. They were a little bit slow coming back, but now, they’ve just been climbing, and for the last month, we’ve seen really good response. We think we can change the frac program and get the same result. You’re going to see an Austin Chalk program that will augment our lower Eagle Ford program next year and the following years. But it basically gives us a STACK play within our Eagle Ford program, which we really can push on and have a lot of efficiency. It won’t interfere with our Eagle Ford program. It will actually be supplemental to that.
Q: You have highlighted some optimism around the Turner wells. What are your thoughts about potential returns for a rig line here?
VP of E&P Patterson: The Turner is one of the best-performing assets we have to-date. Now, it’s early and we only have a handful of wells, but the rates are good. The wells are holding in. We have a lot of running room. Just to give you a feel for where we are in the portfolio, we’ve moved the third rig in. So we’ll have two rigs focused primarily on the Turner for our 2018 and actually, the remainder of 2017.
I’ve got to give real kudos to the culture and especially the operations team in the Turner. As we went out there, we didn’t know much about it. Wells were in excess of 35, 40 days, the initial wells were doing some science, and the costs were a little bit higher than we wanted. Since we’ve gotten the program going, the team has knocked these wells down to under 30 days. We’ve just bought two wells on this week, our most recent wells, and those two wells we’ve adjusted the completions, and we knocked $1.5 million off of each of those completions.
So, where we are today in the Turner is not where we’re going to be tomorrow in the Turner. It’s only going to get better. We’ve had people from Mid-Con and Gulf Coast volunteer to go up and help that team out. So, we’ve got people from all over the country helping us get that Turner program stood up.
CHK: One of our strengths is the way that we use data and information across the company to optimize the asset and each technology from Haynesville and Utica and Eagle Ford and transfer those to these new plays.
Q: I just wanted to hit on your capital efficiency in new well designs. Could you just speak through your completed well cost in each region in the third quarter?
CHK: We’re continuing to test our different designs, so those are something that evolved over time. When we start to look at 2018, lateral length is also a big driver for those as well. So, I mean, when we’re talking Haynesville, for example, there are 10,000-foot wells that will cost about $11.4 million; Turner wells, 8,700-foot laterals for $9.5 million we would estimate right now, but again, expect all those to improve.
Gulfport Energy Corporation (ticker: GPOR)
Q3 highlights
- Net production averaged 1,199.6 MMcfe per day
- Net income of $18.2 million, or $0.10 per diluted share
- Added 10,700 acres in the Utica Shale, 4,100 acres in the SCOOP, and increased NRI on over 5,000 acres by approximately 8% in the Utica Shale during the nine-months ended Sept. 30
- The updated 2017 budget includes approximately $985 million for drilling and completion activities, approximately $45 million for midstream capital expenditures associated with its investment in Strike Force Midstream LLC with Rice Energy, and approximately $130 million for leasehold activities during 2017.
- Projected 2017 average daily net of 1,065 MMcfe to 1,100 MMcfe per day
Utica Shale
Gulfport spud 23 gross (23.0 net) operated wells. Net production from Gulfport’s Utica acreage averaged approximately 987.2 MMcfe per day, an increase of 15% over Q2 2017. The wells drilled had an average lateral length of approximately 7,882 feet.
Gulfport’s average drilling days, from spud to rig release, totaled approximately 19.3 days, for the nine-month period ending Sept. 30, 2017. Well costs averaged approximately $1,122 per foot of lateral in the Utica Shale. At present, Gulfport has 4 operated horizontal drilling rigs active in the play.
SCOOP
Gulfport spud 7 gross (6.1 net) operated wells. Net production from the acreage averaged approximately 194.4 MMcfe per day, an increase of 20% over Q2 2017. The wells drilled had an average lateral length of 7,174 feet. Gulfport turned-to-sales 6 gross (5.6 net) Woodford wells located in the wet gas window in central Grady County, Oklahoma.
At present, Gulfport has four operated horizontal drilling rigs active in the play.
Southern Louisiana
At its West Cote Blanche Bay and Hackberry fields, during Q3 2017, Gulfport spud 6 wells and performed 9 recompletions at the fields. Net production during Q3 2017 totaled approximately 17.1 MMcfe per day.
Gulfport conference call Q&A
Q: As we look at the SCOOP, would the plan be to maintain four rigs? Given the strong wet gas results in the Woodford, would the focus remain on the Woodford? How would you think about potentially folding the Springer and Sycamore zones into the development program if successful?
Gulfport Energy Corporation President and CEO Michael G. Moore: It’s a good question. So, I do think our program next year will be focused on the Woodford wet gas. Obviously, we’ve all seen the results of those wells that we brought on to-date, and we have we have more to come before the end of the year.
As you know, we’ve been testing the Springer and the Sycamore. We have a Springer well to talk about, hopefully in the next couple weeks, it’s still in flowback. Sycamore probably will be towards the end of the year. We will include some Springer and Sycamore testing as well next year, and just stay tuned for details of specific levels that probably heavily weighted towards Woodford wet gas. Woodford will have a six well pad coming on soon.
Q: You just discussed keeping four rigs running in the SCOOP next year and perhaps two or so in the Utica with higher working interest in the Utica. How do you reconcile that with this current view of in-basin gas being evacuated and potential basis improving? How do you think about capital allocation right now?
CEO Moore: We are return-driven as are most companies. Keep in mind that when we talk about less activities in Utica, we have to factor in the efficiencies that we’ve been able to achieve up there, so we can do more with less. We do have acreage to hold in Utica, so we always try to find the right plan that allows us to do that.
As we look to 2019 and beyond, we will be getting close to fully held in Utica. So, I think, that could be a different analysis. We are encouraged by the pricing in the Northeast for 2018 and we do think there’s an opportunity for improvement. But you also got to remember, we’re getting very good pricing in our SCOOP area as well already and we do have additional margin that comes from those.
So, it’s finding the balance between the two areas. It’s slower to drill in SCOOP, faster to drill in Utica. We can do more with less. So, again, staying within that cash flow neutrality is probably the lead governor next year. Certainly, returns are also critical, but right now the returns that we see for the two basins are right on top of each other. So, not as much of a concern right now.
Q: Could you maybe just talk about these efficiencies and maybe just specifically, the drilling times in both the Utica and the SCOOP, kind of maybe from the beginning of the year when you budgeted this year to kind of where you’re looking at them now as we think about these changing rig counts?
GPOR: Certainly, on the Utica side, we continue to make strides. Our drilling days for the third quarter is the single best quarter since we’ve been here. So, the guys in the Utica have done a great job and our days continue to get better in that when you spend less days on location, that’s what we’re looking for.
On the SCOOP side, it certainly has been challenging, to say the least. For the year, we’re at about 69 days per well, which is kind of in line at what we budgeted. We’ve been working on everything in the SCOOP. We have some recent successes for some wells, much less than 70 days, which is very encouraging. We’re working on consistency. We’ve got the right equipment in place. I believe, we’ve got the right people and we will continue to bring days down.
CEO Moore: We haven’t necessarily reached maximum efficiency in Utica, but the bigger step change has probably been recognized. We’ll continue to find ways to roll faster and complete faster. But smaller incremental changes going forward. Our leading-edge wells out there have been very, very good.
SCOOP, I think, has more room for improvement for us. We’ve already seen that on the leading-edge wells, the ability to steer and stay within zone 90% of the time. That’s huge in this play. It’s a very faulted, fractured system here. And the more you can stay in zone using the geosteering tools, the better-off you are and the faster everything goes. It also helps on the completion side. So, we’re really excited about the opportunity for improvement in the SCOOP. And we kind of feel like it’s going faster than expected, but it’s still going to take a while.
