Current EPE Stock Info

‘A couple of engineers are significantly less expensive than a poorly completed well – EP’s Russell Parker’

On February 28, 2018 Ep Energy Corporation (ticker: EPE) announced fourth quarter and year-end 2017 financial and operational results.

Key highlights

  • New leadership team in place
  • 3 thousand barrels of oil equivalent per day (MBOEPD), including 46.1 thousand barrels of oil production per day (MBOPD)
  • $587 million of oil and gas expenditures, including acquisitions of $29 million
  • 149 completed wells
  • $194 million net loss / $691 million Adjusted EBITDAX
  • Entered into Eagle Ford acquisition and Altamont acreage divestiture – closed 1Q’18
  • Improved financial flexibility with extended debt maturity profile

Financial results for Q4 2017 and full year 2017

In Q4 2017, EP Energy reported a $0.29 diluted net loss per share and $0.07 adjusted loss per share, according the company’s press release. The reported net loss for Q4 2017 was $72 million, compared to a $140 million net loss for the same period in 2016. The decrease in net loss was a result of higher realized pricing on oil and NGL volumes and lower reported general and administrative costs.  Adjusted EBITDAX for Q4 2017 was $181 million, down from $255 million in the fourth quarter of 2016, due to $118 million less of hedge settlements and lower total equivalent and oil volumes in 2017 versus 2016.

Operating expenses for Q4 2017 were $217 million, which is $30 million less than the same quarter in 2016, due to lower reported general and administrative costs. Capital expenditures for Q4 2017 were $145 million, which represents a $29 million increase from Q4 2016, due to increased drilling activity in the Eagle Ford Basin in 2017. During Q4 2017 EP Energy completed 30 gross wells, including 14 in the Eagle Ford Basin, seven in the Permian Basin as part of the company’s joint venture, and nine in the Altamont drilling joint venture.

For 2017’s full year, EP energy reported $(0.79) diluted net loss per share and $(0.39) adjusted loss per share. Reported net loss for 2017 was $194 million, compared to a $27 million net loss for 2016, which included approximately $450 million of gains on extinguishment of debt and asset sales in 2016.

Adjusted EBITDAX for the year 2017 was $691 million, down from $1,039 million in 2016 due primarily to $546 million in lower hedge settlements offset by higher realized pricing on oil and NGL volumes in 2017.

Total operating expenses for the year ended December 31, 2017 were $927 million, which represents a $62 million increase from 2016. The difference was driven by a $78 million gain on the sale of the Haynesville assets in 2016.

Capital expenditures in 2017 were $587 million, representing a $99 million increase from the same period 2016.  In 2017, the company spent $227 million in the Eagle Ford, $267 million in the Permian (including $29 million of acquisitions) and $93 million in the Altamont. Throughout 2017, the EP Energy completed 149 gross wells, which represents approximately 50 more wells than EP Energy completed in 2016.

As of December 31, 2017, EP Energy’s balance sheet included $4.1 billion of total debt and approximately $27 million of cash and cash equivalents. In January 2018, EP Energy successfully exchanged and extended the maturity on approximately $1.1 billion of senior unsecured notes maturing in 2020, 2022 and 2023 for new senior secured notes maturing in 2024. As of December 31, 2017, the company had approximately $800 million of total liquidity.

Operational highlights

For the year ended December 31, 2017, average daily production was 82.3 MBOEPD, including 46.1 MBOPD of oil.  Fourth quarter 2017 average daily production was 80.6 MBOEPD, including 43.6 MBOPD of oil.  The decrease in the third and fourth quarter production was due to the timing of Eagle Ford activity that was focused early in 2017.

Eagle Ford Basin

In 2017, EP energy completed 43 wells in the Eagle Ford and production was 35.7 MBOEPD, representing an 18 percent decrease from 2016. In Q4 2017, the company completed 14 wells and produced 30.6 MBOEPD, representing a 19 percent decrease from Q4 2016. EP energy expects to increase year over year annual production for the first time since 2015.

The Eagle Ford horizontal shale inventory was expanded by approximately 200 future drilling locations with the acquisition of producing properties and undeveloped acreage from Carrizo Oil & Gas, Inc., which closed in January 2018.

In the Eagle Ford, EP has increased current production by 20 percent compared to the Q4 2017 average. The increase was partly driven by performance of new wells, and partly driven due to the acquisition. The increased production includes four Ritchie Farms in-fill pad child wells that have been online for 25 days, along with four new Volatile Oil wells completed in December and January that had 60-day oil rates 30 percent higher than predicted.



Permian Basin

In 2017, Ep Energy completed 71 wells in the Permian Basin and produced 28.7 MBOEPD, representing a 34 percent increase form 2016. In addition, EP energy completed several bolt-on acquisitions in Upton County which added current production and future drilling locations. The cost for the acquisitions was approximately $29 million and included approximately 3,600 net acres in the Upton county with gross oil production of 300 BOPD. This transaction added roughly 60 future drilling locations to the company’s portfolio, and enabled EP Energy to extend approximately 20 short lateral locations to long lateral locations.

Altamont Field

In 2017, EP Energy completed 25 wells and performed 59 recompletions in its Altamont Program. Full year production was 17.9 MBOEPD, representing an eight percent increased compared to 2016.

Hedging update

In 2017, EP Energy realized $93 million from settlements on financial derivatives. For 2018, EP Energy has effectively hedged approximately 89 percent of its expected oil production at an average price of $58.47 per barrel, and hedged approximately 56 percent of its expected natural gas production at an average price of $3.04 per MMBtu.

Proved Reserves

EP Energy’s proved oil and natural gas reserves were 392.1 MBOE as of December 31, 2017, representing a nine percent decrease compared to proved reserves at December 31, 2016 of 432.4 MMBOE. Proved developed reserves increased seven percent from 204.6 MMBOE in 2016 to 218.3 MMBOE in 2017. In 2017, proved developed reserves were 56 percent of total proved reserves and 52 percent oil.

The primary reason for the decrease in proved reserves from 2016 to 2017 was divestitures relating to the company’s two drilling joint venture and ownership changes, resulting from higher WTI prices under the variable royalty rates agreement with University Lands. Without the impact of divestitures and ownership changes, 2017 and 2016 proved reserves were essentially the same, the company said.

Conference Call Q&A

Q: Could you give a little more color on some of those parent-child wells? Obviously, there’s been some concern in the industry on the issues with the child well. But it doesn’t seem like it’s occurred with you all. When you look at it, is that related to the reservoir, maybe how the parent well was initially drilled and completed? Or is it just your approach to really putting a specific sort of a drill and complete kind of technique on that child well?

President and CEO Russell E. Parker: Historically, we have seen parent-child interference. That whole situation starts with actually the completion of the parent well. If your completion is inefficient and if your fractures happening at every cluster. If your frac lengths are unequal, then what happens is you get inefficient drainage and you potentially end up creating pathways that will connect to your in-fill wells. It does not mean you’ve actually drained the entire lease. It just means that you can communicate between wells during completion.

And so, what do you do about that? Well, first and foremost, as you’re completing new parent wells, what you really want to do is iterate upon your designs to try to get the most homogeneous frac half lengths on the new well. Now, when you’re coming into an in-fill situation such as with these eight wells, what you really need to look at is: where are the wells landed, do the benches communicate, what’s the hydrocarbon in place, what is our recovery factor have been to-date and are there any indications that we have certain communication pathways during certain parts of the offset lateral that we’re just about to complete. And also, you have to take into account spacing.

So, in certain areas, what you may want to do is actually space your wells a little bit further apart, but you put a little bit larger pound per cluster completion on those wells in order to still drain the same amount of rock. And you may want the clusters even further apart to make sure that you’re not getting negative interference. But it’s a very granular process. We have a number of really high-quality technical staff members here that dig into this, and we’re doing what’s called rate transient analysis and even simulation on the fracture design and how the fracs propagate through the reservoir on each and every pad. It takes a little bit of extra work. You have to roll up your sleeves. But I will say this, a couple of engineers are significantly less expensive than a poorly completed well. So, that’s the approach we’re taking.

Q: And I guess from our seats and the investor seat, the one big concern would be doing this seemed very costly, right? And when everybody else is going in the direction of manufacturing mode and reducing costs and trying to fight service inflation, this seems to be going into the face of that. What are the ways to mitigate some of the cost pressures on being so specific going forward?

President and CEO Russell E. Parker: Two things. One, when you’re trying to mitigate the parent-child interference, part of what you end up finding is that you actually find places in your in-fill well that you do not need to complete, which ends up saving you some costs. So, if you just blast the whole well with the exact same design that you’ve had on other wells, invariably, you’re going to get communication, right. And you ended up completing part of the lateral that you possibly didn’t have to. So, that mitigates part of the costs. The other way to mitigate the costs is to make sure that you have the right contractual relationships with your vendors to where they can make their margin, but you’re not pricing yourself in.

And this is what happens. When you get in manufacturing mode, you end up pricing yourself into one exact design, and the efficiency comes from pumping that same design over and over and over, whereas we tend to look more at, well, how do we get efficient by pumping a certain number of hours in a day and making sure that we’ve solved all of our sand logistics and our water logistics such that the efficiency comes from consistent operation at the surface. But down-hole, we have a very specific design. And the good news is you can execute that specific design with those efficient surface operations. You just want to build your contractual relationships with your vendors around that. And that way, it works as a win-win for everybody. But it’s thinking creatively about how you put all that together.

Q: We’ve spoken here most of the call on some of the operational side, and I wonder if you could talk a little bit more on the financial side, specifically how you’re thinking about balance sheet management, leverage targets and the balance of CapEx and cash flow short to medium-term.

Senior Vice President, CFO and Treasurer Kyle A. McCuen: Leverage ratio wise, I think we talked about on our call last month that we expect to improve year-over-year. Our target is to get to a half turn to a full turn better on total net debt to EBITDAX versus 2017. And then, in terms of improving the balance sheet over time, we are making headway in 2018. We’re reducing the outspend. So, that’s driven by the improvement in the capital efficiency of the assets. So, although we are spending a little bit more capital year-over-year, we’re closing that gap. And so, longer term, it’s to completely close that gap. And so, as we make headway on capital efficiency, we’re going to look at doing accretive A&D, and we think that’s a big part of kind of closing the remaining gap. And so, that’s kind of our plan medium-term to long-term.

President and CEO Russell E. Parker: In 2017 – there’s two ways you get there. One is by reducing your maintenance capital. So, let me speak to that for a minute. In 2017, we thought that number was right at about $600 million. This year, our fully-loaded D&C, so just the base level business drilling and completion, is going to be about $565 million, which is about the same as last year. However, we’re causing a rate bump with that over the year. So, if we were to scale that back down to just hold rate flat, let’s say, to quarter four, if we just wanted to hold that rate flat, we think that number is closer to $500 million now. Because remember, in our CapEx guidance for this year to get to the $625 million midpoint, that includes about $60 million of the new projects that we’re really not giving ourselves any rate for now – or rate credit for at this point.

Now, you have to do those things as an organization, because in order to get the inflection point to make our capital more efficient, you have to be willing to take that risk and do that in the near-term, because we firmly believe one or more of these opportunities that we’re pursuing is actually going to show to be even more capital efficient, have lower F&D costs and help us reduce our maintenance even more. So, I look at it, if we just want to say, hey, look what’s the base business maintenance capital? We think for this year it’s probably now around $500 million. And honestly with some of these changes that we’re making, we hope to drive that down into, say, the $450 million or low-4s with time.

And as you drive that maintenance capital level down, then you get to the point where that EBITDA generation increase, you’re actually moving towards cash flow neutral after paying interest and G&A. Our G&A run rate is also down year-over-year as well. So, that also helps. Now, in addition, Kyle’s comment is exactly right. In addition, in any good oil and gas company we’re looking for, we always want to look for accretive A&D. That may be 640-acre leases that we’re taking and bolting and blocking in to some of our best acreage, or it may be more transactions like you saw us just execute. But we believe with the combination of them, then you’ll start to see that that debt to EBITDA ratio come down, and that’s how we’ll get to free cash flow neutrality.

Q: And then, my follow-up is with regards to capital allocation between the plays. You’ve talked about some of the improvements that you’re seeing in the Eagle Ford. What would you need to see positively or negatively and what is the scope for further shifts or increases in capital between the Eagle Ford and the Permian in particular?

President and CEO Russell E. Parker: Well, we need to see these new tests, and it’s going to take us about six months really between testing the new zones and seeing what our completion designs do. And also with the infrastructure gains that we’re making in the Permian, we think that’ll give it a little bit of a leg up on the Eagle Ford possibly going forward. But ultimately, what it’s going to come down to is as we test these new ideas and this just gets to our core business properties, right, you got to innovate, execute and then evaluate, we go back – and we evaluate every month, by the way. Every month, we would roll off projects and we roll on projects to see how we’re doing from a F&D standpoint, rate of return standpoint, and dollars per BOE a day standpoint. And then right now, we haven’t seen enough to change the allocation. But I would anticipate as we go through the year and we get these results, we will probably see things that would change that project list to sort differently, right, and then we’ll reallocate capital as per the results.



Legal Notice