Antero Resources, one of the biggest Marcellus/Utica drillers (pure play) released first quarter 2019 numbers yesterday. The Mariner East 2 (ME2) pipeline, which Antero uses to ship and sell natural gas liquids (NGLs) had a huge beneficial effect for the company. Antero’s production was massive: 3.1 billion cubic feet equivalent per day (Bcfe/d) in 1Q19, up an astonishing 30% from 1Q18. But here’s the kicker: Nearly one-third of Antero’s production (29%) was NGLs. Without ME2, that big number would have been a small fraction of Antero’s production.
Drilling down on the “liquids” numbers, Antero’s NGL production averaged 148,003 barrels per day (Bbl/d), up 44% over 1Q18. Antero’s NGL production contributed 35% of the company’s total product revenues (before hedges). It’s a critically important part of the company’s revenue stream.
As we’ve observed over the years, Antero has what we consider the best “hedging” in the industry. Hedging means to pre-sell your production at locked-in prices, up to a year (or more) in advance. Somehow Antero is able to guess where the price of gas is going and lock in prices that far exceed the average price of gas at the Henry Hub. Example: In 1Q19, Antero sold their natural gas equivalents at an average price of $4.00 per thousand cubic feet equivalent (Mcfe). The best price we’ve seen so far for average price received by M-U drillers in 1Q19 was Cabot, selling theirs for $3.35/Mcf (see Cabot O&G 1Q19: Production Skyrockets 21%, $308M Free Cash Flow).
Incidentally, Antero’s 3.1 Bcfe/d is 35% larger than Cabot’s 2.3 Bcfe/d in 1Q19. Antero is a powerhouse in the Marcellus/Utica.
On the financial front, Antero made nearly one billion dollars–$979 million–in net income in 1Q19, versus making $14.8 million in 1Q18. That’s a huge swing!
On the operations front, Antero drilled 36 wells with an average lateral length of 10,000 feet in an average of 11.6 total days from spud to final rig release, a 6% reduction in total drilling time from 2018 levels. The company placed 23 horizontal Marcellus wells online to sales in 1Q19.
For the rest of 2019, Antero plans to operate an average of four drilling rigs (including three large rigs) and an average of three completion crews. That’s down from the five rigs and four completion crews they operated in 1Q19. In 2019, Antero expects to drill 120-130 wells and place 115-125 wells online, consistent with their previous estimates. Massive!
Here’s a copy of the full Antero 1Q19 update, with financials:
2019-05-01_Antero_Resources_Reports_First_Quarter_2019_167
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As we like to do, we read over the transcript for the Antero conference call with analysts. We found some interesting nuggets.
We’ll begin with Antero CEO Paul Rady’s prepared/opening comments. He opens his talk with the importance of ME2 and talks a lot about liquids:
Let’s begin with the discussion on our firm transportation position both for natural gas and natural gas liquids. I’ll first touch on the natural gas liquids firm transportation given the recent start-up of Mariner East 2.
As outlined on slide 3 titled inflection point in NGL Marketing and Pricing. We began shipping volumes for the first time in February through our commitment on our Mariner East 2 pipeline, a pipeline that transports NGL volumes from fractionators in Southwest Appalachia to the market sub-facility in Philadelphia for exports into the global markets. We have 50,000 barrels a day of propane and butane capacity contracted on the pipeline, which equates to about one-third of the available capacity on ME2 today. As the largest shipper on ME2 and with approximately 50% of our NGL production being sold into premium international markets today, we are well positioned to deliver peer-leading NGL price realizations going forward.
As you can see from the table, on the left-hand side of the page, our NGL realizations increased from 52% of WTI before ME2 was in service in January, to an average of 61% of WTI after it came in service. This substantial uplift boosted cash flow by approximately $20 million during the first quarter. This uplift is particularly impressive when you consider that this occurred during a seasonally strong quarter, when in basin pricing is typically strong.
As you can see from the swooping arrows on the map in the middle of slide 3, we exported 29% of our C3+ NGLs in the first quarter, but expect to export 50% for the full year as export volumes ramped up to this level through the first quarter. Although, the relationship between Mont Belvieu NGL prices and WTI crude prices has disconnected a bit in recent months, we expect our C3+ NGL prices to be approximately $4 per barrel higher on an absolute basis compared to our original guidance back in January. This increase in expected NGL realizations is due to the strength in WTI crude prices and also a strong international demand for NGL products out of Marcus Hook, the terminal there.
In recent months, we have seen significant spreads between international pricing and Mont Belvieu pricing as you can see on slide 4 titled attractive international spreads. Our meaningful exposure to international NGL prices allowed us to benefit from this spread during the quarter and we expect that diversification will benefit us throughout the year.
This provides yet another example about how our diversified transportation portfolio reduces both pricing and operational risk around any one particular geographic area or pricing index.
On the ethane front, volumes are expected to pick up slightly with the restart of Mariner East 1 last week. This pipeline had been shut down for the majority of the first quarter. Though we were able to reject this volume and sell the ethane as gas value during the quarter, this resulted in 50 million cubic feet equivalent per day less production during the first quarter on a natural gas equivalent basis.
But importantly, we have the flexibility to reject any remaining ethane industry above our contracted volumes and volumes required to meet pipeline specifications and sell the ethane at natural gas value to maximize overall profitability and cash flow.
Based on current strip pricing for the remainder of 2019 we intend to continue recovering ethane only at levels necessary to fulfill ethane contracts and meet pipeline specs.
For the full year of 2019, we expect to recover total ethane volumes in the range of 38,000 to 42,000 barrels a day down from our previously guided range of 48,000 to 52,000 barrels per day that we set in January of 2019. To the extent that ethane prices improve to levels that support ethane recovery economics we would elect of course to recover additional ethane volumes.
Shifting gears to discuss our natural gas firm transportation position and the long-term benefit it provides, I’ll direct you to slide 5 titled, firm transportation portfolio is a strategic advantage. With the entirety of our committed firm transport now in service, you can see the significant visibility that our FT portfolio provides us with respect to our long-term development plan.
For 2019 we are forecasting natural gas price realizations at a $0.15 to $0.20 premium to NYMEX and expect to continue realizing premiums to NYMEX in the coming years. Unlike many of our peers that are relying on local basins to remain tight in order to develop their asset base over the long-term, we have significant visibility and confidence as it relates to the realized price we will receive due to our transport portfolio to premium markets.
This enables us to make longer-term decisions about the business and focus on what creates long-term value for our shareholders. While we are not fully utilizing the pipelines today we expect our net marketing expense to decline each subsequent quarter moving forward with the first quarter of 2019 being our peak level.
This marketing expense will be virtually eliminated by 2022 when we expect to fill our premium firm transportation. It is important to note that our net marketing expense is offset by our industry-leading hedge position which will deliver $0.20 per Mcfe in 2019 at strip pricing along with the benefits that our FT portfolio provides through delivering volumes into premium-priced markets.
Among these premium markets is the Gulf Coast which is illustrated in purple on the chart indicating our peer-leading 2.1 Bcf a day of capacity into that market. This provides us with tremendous leverage to the growing LNG export market and the NYMEX-based pricing typically associated with long-term LNG supply contracts.
We currently supply 630 million cubic feet a day total. And by the end of 2019 we will be supplying 700 million cubic feet a day to LNG facilities for export making us a top supplier to U.S. LNG markets.
LNG markets are expected to increase by 3.9 Bcf a day in 2019 as illustrated on slide number 6, titled growing LNG market. There are also multiple second wave projects seeking FID this year. Our significant firm transform capacity into the Gulf Coast region provides a tremendous opportunity for us to benefit from this robust growth.
We expect our firm transportation portfolio to become increasingly valuable as LNG players look to secure long-term supply agreements with strong counterparties who have confidence in their drilling inventory over multiple decades. Antero has the production base, the drilling inventory depth and quality, the transport portfolio and the balance sheet to be a very strong player in the LNG supply business.
Now to briefly touch on our 2019 development and capital plan, we placed 23 wells to sales during the first quarter, all on our liquids-rich Marcellus acreage. We drilled 36 wells during the first quarter with an average lateral length of 10,000 feet. In the second quarter, we plan to place 41 wells to sales including 23 that were placed to sales in April. This increase in sequential activity from the first quarter to the second quarter with a focus around liquids keeps us on track to achieve our full year average production guidance.
Turning to our capital plan, we recently reduced our rig count and completion crews by one each. We now expect to run four drilling rigs and three completion crews on average through the remainder of 2019.
As a result of the reduced rig and completion crew count for the remainder of 2019, we expect drilling and completion CapEx in the second and third quarters of 2019 to be in the low $300 million area. Further, we are reducing our full year 2019 CapEx guidance to $1.3 billion to $1.375 billion the low end of our prior range.
Before I turn it over to Glen, I’d like to discuss the many positive advancements we are seeing on the operational front. Turning to slide 7, titled Drilling and Completion Efficiencies Continue, I’ll jump to the top right quadrant of this page and highlight that we continue to push the average lateral feet drilled per day higher. We drilled an average of 5,300 lateral feet per day in the quarter, the highest quarterly rate in company history, representing a 14% increase in lateral footage performance compared to 2018.
Most impressively, we recently set what we believe to be a world record in the category of drilling lateral feet in 24 hours where we drilled a horizontal well and drilled sideways 9,184 feet in 24 hours on the Antero Hayhurst Unit 2H well which is in our rich gas play fairway. While we’re very proud of the record set here, we’re also very pleased with the continued and consistent move higher in average lateral feet drilled per day.
Completion stages per day in the Marcellus averaged 5.3 stages per day for the first — for the full quarter higher than our overall 2018 average. This is a noteworthy number as the first quarter is typically the most challenging from a seasonal standpoint due to winter conditions.
Given our full year 2019 budget which assumes 5.2 stages per day, we feel very good about our continued efficiencies leading to lower well cost throughout the year. An increase of one additional stage per day does result in about $200,000 of savings per well. So, it’s important to us.
We continue to be focused on operational efficiencies that will drive well cost lower. A progress that we have exhibited already in 2019 gives us confidence in achieving our full year production targets with spending at the low end of our capital guidance range.
We have achieved significant scale and product diversity as the largest NGL producer and the fourth largest natural gas producer and we have a firm transportation portfolio structured to deliver best-in-class price realizations for our products even in a difficult operating environment. These attributes combined with our peer-leading core drilling inventory position us to deliver attractive long-term returns to our shareholders for many years to come.*
The slide deck Paul referred to during his talk:
Antero-Company Website Presentation – May 2019 vFF
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We found some real gems in the Q&A that followed the prepared presentation on the conference call, including this one about Antero’s total focus on the Marcellus, and (for now) excluding any new Utica drilling:
Jane Trotsenko
Okay, got it. My second question is on Ohio, Utica. Could you please remind us how you view this asset in terms of capital allocation and in terms of production trajectory going forward?
Paul Rady
Yeah. We like our Ohio, Utica project both on the rich side as NGLs have gotten stronger, our rich gas trend has become more economic and also in the dry gas areas where we have accumulated acreage in a very good reservoir quality areas. So we like the project quite well but it still doesn’t compete with Marcellus and so that is our focus that still the Marcellus economics are better. Therefore, our capital is almost 100% dedicated to the Marcellus at this time but very much likely Utica still.
Jane Trotsenko
Okay. But should we think about Utica as kind of flat for the production trajectory or will it be declining?
Glen Warren
It’ll probably be flattish I would say that we drill a half of a pad or a full pad every year. And so that can keep production flat.*
A question and answer about the costs of drilling a Marcellus well, and how the company is working to keep costs down:
Holly Stewart
Okay. That’s great. And then maybe I thought slide 19 did a good job of just the waterfall of well cost in the Marcellus. Could you just maybe provide a little bit of color around the inflation that you have seen and then some of those renegotiated completion contracts?
Paul Rady
Yes. We do see certainly pressure. We do a lot of water hauling of course from the well sites both flow back water and produced water. And so there’s — there has been pressure on trucking cost especially driver cost, but we’ve been able to trim back and use fewer trucks as we’ve gotten more efficient in call-outs and so on. So yes, there is some pressure there. But on the other hand the renegotiation of certain contracts like the self-sourcing have been very beneficial.
Right now, we are self-sourcing at least 70% approaching 80% of our sand needs for this year, it’s working out quite well. We’re contracted with suppliers that can actually barge up the Ohio River which is quite a cost savings from — railing from the traditional Northern White trends, we saved quite a bit there. And we have staging facilities on the Ohio River right next to our acreage. We do have in case that there are ice dams and so on, on the Ohio.
In the winter, we do have quite a good amount of sand set aside to fall on if there are any logistical hitches. So that has really reduced our sand cost, which are significant by about one-third so far and expect to see that translate through. So I’m talking about not only the sand itself, but the last mile. So we’re getting those costs down. Those add up to the several hundred thousand dollars per well. So seeing those efficiencies with bigger pads as you know we can get off more stages a day just to the logistics on the pad. So a lot of efficiencies that are helping to bring our well costs down.*
Another Q&A about the Utica, which clears up any lingering confusion: No, Antero is not drilling in the Utica, for the balance of 2019:
Subash Chandra
Yeah. Got it. And then the slide on drilling — D&C efficiencies. Slide 7, shows Utica results, is there Utica activity underway?
Michael Kennedy
Hi. Subash, this is Mike. We do not have a drilling rig in the Utica, we did have one completion crew there for part of the first quarter where we completed one pad. But there’s no further activity throughout 2019.*
How long are Antero’s laterals, and how much sand (proppant) are they using?
Jane Trotsenko
Do you see laterals getting longer year-over-year? And then in terms of proppant lodgings is it going to change next year?
Paul Rady
Yes. We have such a strong inventory that we have our program planned out for the next five or six years in terms of which specific laterals, which specific units we are going to drill and they do get longer year by year how much per year? If they’re averaging 11,000 to 12,000 this year they get out into the mid to high 13000s over the next several years.
But we have just found that it’s more efficient in terms of cycle time and so on to — that’s the sweet spot in the 13,000, 14000-foot range. A little longer than that and there’s just such delays in completing the wells. So we’re happy with that. And what was the second part of your question again Jane sorry?
Jane Trotsenko
Proppant intensity. How much proppant are you going to use? Is it going to change? Or is it going to remain the same?
Paul Rady
It will probably remain the same. We feel good about 2000s in some of our step-out areas. We sometimes go to 2500 pounds per foot. But generally we’re happy in that scenario of 2000 pounds per foot. Every now and again we do 17.50 pilots to check that out. And so we continue to learn, but I’d say it has mostly stabilized around 2000 pounds per foot.*
*Seeking Alpha (May 2, 2019) – Antero Resources Corporation (AR) CEO Paul Rady on Q1 2019 Results – Earnings Call Transcript
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