Ranger Oil Corp (ROCC) 2017 Q1 法說會逐字稿

Greetings, and welcome to the Penn Virginia Corporation First Quarter 2017 Earnings Conference Call. (Operator Instructions) As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Mr. John Brooks, Chief Operating Officer and Interim Principal Executive Officer. Thank you, Mr. Brooks. You may begin.

Thank you, Michelle. I'm also joined today by Steve Hartman, our Chief Financial Officer. Prior to getting started, I'd like to remind you of the language in our forward-looking statement section of the press release, which was released yesterday, as well as in our Form 10-Q, which will be filed today. Our comments today will contain forward-looking statements within the meaning of the federal securities laws and these statements are subject to a number of risks and uncertainties that could cause actual results to be materially different from those forward-looking statements, including those identified in the risk factors of our annual report on Form 10-K and quarterly reports on Form 10-Q, filed with the Securities and Exchange Commission. Cautionary language is also included on Slide 1 of our earnings release presentation, which we will use to go through our discussion today. That presentation is available on our website, and I encourage you to open it, if you haven't already.

So with that, I'll turn to the presentation, starting on Slide 2. We're very pleased with our first quarter results. Our production exceeded the top end of guidance at 855 MBOE, or 9,495 BOE per day. Financially, the quarter was very strong too, and Steve will discuss the quarterly results in a few minutes.

Operationally, we recently turned our Kudu 100 pad in line to sales. This is our first 4-well pad we've drilled since restarting the drilling program last November. These wells are also our first test of 400-foot lateral spacing using our latest completion design, which targets 2,500 pounds of proppant per foot of lateral. The Kudu wells have somewhat shorter average lateral lengths at around 5,400 feet. The 24-hour IP for the pad was 5,889 barrels of oil equivalent per day, or 283 barrels of oil equivalent per day per 1,000-foot of lateral exceeding our type curve. They haven't been producing long enough to establish a full 30-day IP yet for the pad, but it looks like we're on trend to achieve around a 3,500 BOE per day rate for the pad, or 160 BOE per day per 1,000-foot of lateral. This is a tick under the type curve for this snapshot in time, but the wells are continuing to clean up frac fluids so we're still encouraged that these are good wells. It's worth noting that these are downspace wells so we'll be encouraged with results at or near the type curve. It's also worth mentioning that these are infill wells in the unit. The Kudu 1, 2, 3, 4 and 5H were drilled in 2011, 2012 and 2015, so there's been nearby offset production in the unit for several years. Yet even with active production in the unit for over 5 years, production appears to be in line with expectations and is still cleaning up. We've also seen production uplift in some of the existing parent wells. Three of the 5 parent wells in the unit are currently flowing without artificial lift, where they had been previously on rod pump or gas lift for several years. Typically, a well will pressure up and unload significant water volumes, accompanied by increased oil and gas rates. That's an economic benefit that we don't capture in the IP rate metrics, but it definitely helps with overall production. We've now observed this uplift in most of our slickwater completions to varying degrees, and I think it's safe to say that overall, we're not negatively impacting offset wells and often improving them. Under our previous hybrid fracs, we did not observe this beneficial effect nearly as often, and frac heads were typically negative.

Another thing we did differently on the Kudu pad was our perforating scheme. We have previously been using 5 tapered clusters spaced 40 feet apart. We continued with that scheme on our 2 interior Kudu wells. But on the 2 exterior Kudu wells, we used 8 clusters spaced at 20 feet. This changing cluster design yielded superior results in the exterior wells relative to the interior well, so we'll continue to use it and further refine it.

Also, I want to give you an update on our Axis pad. The Axis pad is our northernmost, up-dip drilling unit which is shallower and oilier and has lower gas oil ratios. We reported on the last earnings call that the 24-hour IP was encouraging for the pad. That 24-hour average IP in the 3 Axis wells is 2,114 barrels of oil equivalent per day, with 93% oil, which equates to 1,969 barrels of oil per day. Normalized to a per foot basis, this equates to 124% of BOE per day and 119% of BOE per day on the type curve.

The average 30 days for the 3 Axis wells pad is 1,268 BOE per day, with 93% oil, which equates to 1,179 BOPD. Normalized to a per foot basis for oil-only, the average Axis IP equates to 167 barrels of oil per day per foot, compared to 169 barrels a day per foot on the type curve. On an oil equivalent basis, this equates to 179 BOE per day per foot compared to the type curves of 189 BOE per day per foot. The gas oil ratio tends to decrease as you move up dip, so it's not surprising that the gas content is lower in this unit than for the overall field average. It is, however, very good that we are seeing the oil production exactly where we want it to be.

We're also very excited about our recently completed Lager 3H. This is the company's first test of slickwater frac completions in Area 2, which is deeper, has higher pressures and requires a third string of casing. The lateral was over 8,000 feet long and we pumped 40 stages with 2,450 pounds of proppant per foot on average, using 8 clusters per stage, spaced at 25 feet. We just commenced flow back operations late last week, so we have not established the 24-hour IP yet. But we are very excited about the early results from this well, especially with the high pressures we're seeing. It's very early in the flow back cycle, but we've already passed the 2,000 BOE per day mark, with 78% oil and close to 4,800-psi on a [20 64 show]. It's important to note that we are not saying this is the 24-hour IP for this well, as peak production has not yet been established. However, this is a critical test to evaluate slickwater completions in Area 2, and continued success in applying slickwater completions to our Area 2 acreage has the potential to drive changes to our drilling schedule. We have a second Area 2 test scheduled for later this year after we've had some time to evaluate the Lager results, and that shows up as the Schacherl-Effenberger 3 on our activity map that follows. That pad is just down-dip of where we map the pressure transition and would be a useful data point in extending the successful application of slickwater completions in Area 2.

That pad was originally scheduled as another single well test, and we're currently evaluating accelerating the timing of that pad, as well as whether or not we'll make it a 2-well pad. We also have other candidates under consideration for our next Area 2 slickwater test, so that may give you a feel for how our drilling schedule could change in the second half of the year.

Another thing to note, we're still adding acreage in our core area. We have leased and/or extended about 1,700 net acres in and around Area 1. For competitive purposes, we obviously don't want to discuss exactly where we are adding acreage or at what cost, but we've generally been able to replace most of the locations we've drilled in 2017 with new inventory at a reasonable cost, maintaining our approximately 525 drilling locations and in line with our capital program guidance.

Our liquidity remains strong, and we have one of the best balance sheets in our peer group. And Steve will get into more detail, but we have about $100 million of liquidity right now with $35 million drawn on our credit facility, with $128 million borrowing base. We are finishing up our spring redetermination, and we expect our borrowing base will be meaningfully higher so we expect that liquidity number to go up, and that extra liquidity positions us very well for growth. Our capital guidance for 2017 is unchanged at $120 million to $140 million. We can accelerate in the right environment, and we continue to evaluate that. We expect 20% to 30% production growth for the fourth quarter 2017 over the fourth quarter of 2016, assuming a 2-rig development program. We expect total production growth in 2018 to be 20% to 30% over 2017, again with 2 rigs running and drilling within cash flow for the year.

On the next slide, Slide 3, is our activity map. As we did last quarter, we show you approximately where we designate the divide between Area 1 and Area 2 acreage. You can see where the Lager 3H is, down-dip at the pressure transition zone and on strike with EOG's Guadalupe Unit, which had excellent results. The Lager is also very close to EOG's Kasper and Boedecker units, both of which also had excellent results. You can also see at the top of the map where our Axis pad is located. And as I mentioned, you can see that it is in the shallower part of our acreage so we are very encouraged by the results in that pad, especially given the high percentage and good quality of the oil.

I'd also like to highlight the 4-well Jake Berger pad and 4-well Chicken Hawk pad on the map. These 2 pads are southeast and just down dip of our Axis pad. We're currently drilling on the Chicken Hawk and we recently changed our drilling schedule so that we will use our second rig to drill the Jake Berger pad concurrently and then frac the 2 adjacent pads together as 1, 8-well super pad. We think that will provide the best stimulation of the rock and should save cost. The only downside is that pushes the Chicken Hawk completion into the third quarter, so second quarter production looks to be flat to the first quarter. We expect the new production from the Chicken Hawk and Jake Berger pad to come online in August or September, so the third quarter looks to have some very significant growth.

On the next slide, Slide 4. Like to highlight once again some details of our recent well results. I already mentioned the Kudu pad is coming online pretty much as expected and in line with the type curve. And you can see in the chart at the bottom of the slide, that the pad came on with very strong IPs on a per 1,000-foot of lateral bases, exceeding the type curve and then coming in a tick below in IP 30. Remember these wells are completed with our latest completion design, with 2,415 pounds of proppant per foot, which is also accompanied by an increase in frac fluid, so the wells take a little longer to clean up. There's a very high percentage of oil, as you could see, climbing to 94% oil for the 30-day IP, up from 92% in the 24 IP. As I mentioned earlier, we changed our cluster geometry on the 2 exterior wells and they are outperforming the 2 interior wells, so we're using that cluster speed going forward and we'll continue to refine it.

The Axis and Sable wells also continue to do well. We drilled out the remaining plugs in the Sable 6 recently and the well responded with an increase in production, but its early time production had been hampered by that obstruction, so we've included it from the Sable pad metrics in the table, given its mechanical constraints. The Axis 30-day IP for oil is in line with the type curve, but the gas component was a little lower. The gas oil ratio is lower as we drill updip in the shallower, oilier part of our acreage, and the actual gas content can be a little challenging to predict with precision. However, we're very pleased with the progress in the Axis wells. The takeaway on this table is that we have very strong IPs in a fairly tight distribution of IP 30s that overall, are in line with expectations. What we're most excited about though, is the Lager 3H. We are watching this well closely, as this will be a strong data point in formulating our development plan for Area 2. Early indications point to the Lager being a strong and successful test of the slickwater completions in Area 2, which could be a game changer.

First off, we could increase the number of wells drilled on the Schacherl-Effenberger pad, which is currently scheduled as our second slickwater appraisal test in Area 2. We could also make this a 2-well pad instead of a single well as it's currently scheduled. Additionally, we also have a large inventory of other area 2 locations from which to choose, if we were to change the drilling schedule to add in more in Area 2 drilling. Our working interest tends to be higher in Area 2, so that would be a change to our capital program and anticipated production. We also have the option of accelerating the development program by adding a third grade, concentrating on Area 2 development. And that also depends on commodity prices, but we do have the liquidity and flexibility to bring on that rig. We will be rate of return driven, so these decisions depend on commodity prices, well cost and production results.

On Slide 5, you can see our Area 1 type curve in economics. You saw this is slide in our March earnings call. The type curve has not been changed. We still think well costs are in the previous guidance range of $4.9 million to $5.1 million. We have seen some increases in service cost, particularly on the completion side. But we're still comfortable with this range for now. Our economics are shown in the upper right. At $50 oil, we expect to see around a 50% rate of return. And at $55 oil, that rate of return increases to around 70%. You can see the pickup in value when we switch to slickwater compared to our older hybrid completion design. We are continuously working to optimize our well designs and improve operational execution to control our cost and increase well productivity and keeping with our focus on rate of return, along with production growth. And with that, I'll turn it over to Steve to go over the financials.

Thanks, John. I'll start on Slide 7 with an overview of our first quarter financials. Total product revenue for the quarter were $34.7 million, or $40.63 per BOE, with 87% of our revenues derived from oil sales. That, plus 7.4% increase over the prior quarter, primarily driven by higher realized commodity prices and slightly higher oil volume, offset by lower natural gas and NGL volumes.

Cash direct operating expenses were $12.8 million for the quarter, or $14.97 per BOE, which is a slight increase over the prior quarter, primarily as a result of slightly higher LOE, offset by lower production and ad valorem taxes and lower G&A expense.

Operating income was $11.9 million, which is a 16.3% increase over the previous quarter. We recognize the derivative gain for the quarter of $17.1 million compared to a loss on derivatives in the prior quarter of $12.3 million. This was mostly related to a noncash change in the fair market values of the derivatives portfolio, which was driven by a decline in the WTI oil pricing during the quarter.

We paid $2 million in cash settlements on derivatives during the quarter. We reported $28.4 million in net income or $1.89 per share, compared to a net loss of $1.9 million or $0.12 per share in the prior quarter. Adjusted EBITDAX, which is a non-GAAP measure reconciled in the appendix of our presentation, was $20.5 million for the quarter compared to $21.1 million in the prior quarter.

On Slide 8, we highlight our liquidity position. At the end of the quarter, we had $30 million drawn on our $200 million credit facility, with $128 million borrowing base. This is the only debt that we have at the company. Currently, we have $35 million drawn on the facility, $800,000 outstanding in issued letters of credit and $4.7 million in cash, giving us liquidity of $96.9 million.

Our spring borrowing base redetermination is still in process. I expect we will close on the new borrowing base within about a month. The redetermination is going well, but I can't speculate at this time as to what the final redetermined borrowing base will be. But I fully expect it will be a meaningful increase to the borrowing base we currently have and will add significantly to our overall liquidity.

Our leverage is still very low, 0.4x total debt to adjusted EBITDAX at quarter-end. We intend to fund our capital program for 2017 predominantly with cash flow from operations and with the credit facility. I mentioned on the last earnings call that I expect our cash outspend for 2017 should be around $20 million to $40 million, with oil prices in the low $50s. And I think that, that's still the case. We have borrowed an incremental $10 million on the credit facility in the first 4 months of the year, with WTI oil prices to-date in the high $40s and low $50s, so we're on target to keep our outspend within that range. I would expect to fund our 2018 program within cash flow, given our current 2-rig program as planned, and our liquidity, low leverage and good support from our bank group gives us flexibility to finance good acquisitions or accelerate the drilling program, as John mentioned.

On Slide 9, we highlight our full year 2017 guidance and 2018 production guidance. Full year guidance for '17 and '18 has not changed, so I won't go into much detail there. But what has changed is now we are providing second quarter production guidance. We expect second quarter production will be relatively flat, as John mentioned, to first quarter production, with a guidance range of 9,300 to 9,700 BOE per day. As John explained, this is primarily due to the change in the drilling schedule, allowing us to complete the Chicken Hawk and Jake Berger pads together. This pushes production that we have previously expected to come online in second quarter into third quarter. You can see in the graph in the lower right, that we expect strong growth in the third quarter with those 2 combined 4-well pads coming online together, where previously they staggered between the 2 quarters. We don't expect a material change in our anticipated full year production as a result of the schedule change. We are still projecting 10,000 to 11,000 BOE per day of production for full year '17. And a fourth quarter exit rate for the year of 11,200 to 12,100 BOE per day.

Given our fourth quarter 2016 exit production rate was about 9,300 BOE per day, we are still protecting a 20% to 30% growth rate through fourth quarter 2017. And looking forward into 2018, we are still expecting a full year production rate of 12,600 to 13,700 BOE per day, and a fourth quarter 2018 exit rate of 13,500 to 14,500 BOE per day. That would amount to a 20% to 30% growth rate in 2018 over 2017.

It's also worth mentioning that we have our eye on 15,000 BOE per day as a production goal. We're not quite as there yet, as you can tell from our guidance, but success in Area 2 can certainly help us reach that goal sooner.

On Slide 10, we highlight our hedges. We have not had any hedges since the last earnings call. We have 4,408 barrels of oil per day hedged for 2017 at $48.62; 3,476 barrels of oil per day hedged for '18 at $49.12; and 2,916 barrels of oil per day hedged for 2019 at $49.90. For the remainder of 2017, if we use the midpoint of production guidance, we expect to be about 54% hedged for the remainder of the year. We do not have any natural gas or NGL volumes hedged. And the value of our hedged portfolio as of the end of the first quarter was a net liability of $8.7 million. And with that, John, that's the end of the financial review.

Thanks, Steve. So to conclude, on Page 11, we have an excellent acreage position in the Eagle Ford oil window, in which we've the ability to deliver consistent operational execution, coupled with strong financial performance, a pristine balance sheet and solid liquidity. This has us positioned with a substantial inventory of high rate of return drilling opportunities that provides a long runway for organic growth. And with that, Michelle, we'll open up the line for the Q&A portion of the call.

(Operator Instructions) Our first question comes from Welles Fitzpatrick with Johnson Rice.

On the 1,700 net acreage that you added, can you help us out a little bit, was that more in Area 1, Area 2, is that spread around? And is there any cost that you might be willing to share with us there?

Well, I can't say that some of it was immediately adjacent to the Axis pad, so we locked up some expired acreage that needed -- we needed to form up a couple of more units there to directly offset the Axis. And in the rest of it, at this point, we really don't want to talk about just where we're targeting that acreage acquisition or the cost, for that matter.

Okay. But it's safe to assume that it is perspective for the lower Eagle Ford, specifically?

I think it's perspective for the Lower Eagle Ford, the Upper Eagle Ford and potentially, the chalk.

Okay. Perfect. And then just one last 1, the friction reducer that you guys use in the Kudu, can you remind me, did you use that on all the wells on that pad and do you think you're going to keep that up, going forward?

Well, the -- I think what you're talking about is what tailed in with, is that what you're referring to, Welles?

Yes, that's right, the one that was, I think it was on the Axis 3H, but just the 1 out of the 3, yes.

Yes, I'll touch on that. I mean, with all the increased sand volumes that we've been pumping, in some of our previous wells, we had encountered a lot of sand during our coil tubing drill-outs, not so much making it during the production phase or flow back, but we were seeing a lot of sand in the lateral itself. And that does present a mechanical risk and slows the drill-out portion of it. So what we tried is, the experiment on the Axis 3, it's really, we're just upped the concentration of the fictions reducer on the last tail-end of each stage, to try to use them, much higher viscosity to lock the proppant into the wellbore so that we don't -- or outside of the wellbore so that we don't encounter it during drill-out. That was a success on the Axis 3. And then so we repeated that on all of the Kudu wells, as well as our Lager well. And that's really pretty much eliminated most of that problem.

Our next question comes from Jeff Grampp from Northland Capital Markets.

Wanted to go back again on the Kudu wells and maybe talk a bit, John, about the differences in the cluster spacing that you guys did. Could you talk, I know it's still early days, but any kind of quantification of what type of out-performance you're seeing? And then, can you give us a sense for what kind of cost differences are between kind of the base case and the reduced spacing on those?

Well, the 2 exterior wells, the Kudu 9 and the Kudu 6, did outperform and are out-performing the 2 interior wells. It's probably on the scale of about a 5% to 10% difference. It's a small incremental difference that we noted, probably a little higher on the 9%, but probably in 5% to 10% on the 6, so. We basically did that to have more of a limited entry effect, to further refine the completion so that we get even less of a frac length extension and stimulate more of the rock in the near wellbore volume. On the cost side, we're still tracking where we were on our type curve, maybe a little bit below on the last 7 wells, which would be the 3 Axis and the 4 Kudu wells. So we've been able to hit or beat those AFEs. I think on average, those AFEs were about 4.8 and we've been hitting that. The Kudu 9 was a little bit more expensive, even though it's a shorter lateral, because we did drill a vertical pilot well, due several suites of logs and obtain some sidewalk course, but even that well was, even with the shorter lateral, Lager was right on track. So we were able to get those last 7 wells on average of right around $4.8 million, was the AFE. And all indications are that we are at or below that overall. And that is still with the targeting 2,500 pounds per foot.

Okay. Great. Very helpful color, and on the Lager well, I know it's still super early days here, but I guess, just based on your experience in Area 2 and with industry results there, can you guys kind of talk maybe a bit about how long kind of flow back tends to go before you get a peak rate? And just generally, what you've seen out of Lager and peers with slickwater, maybe give you guys a sense for, is the Area 2 going to be return competitive with Area 1, could it be superior, or just kind of any commentary you can provide on that front would be helpful.

All right, Jeff, as I mentioned on the prior call, our test in Area 2 of our slickwater completion is focused on making Area 2 results compete with rate of returns that we see in Area 1. The costs are higher to drill in Area 2. But as these results show, the results can also be a little higher than you would expect. We're being pretty careful with the flow back because it's such high pressure and we're going to monitor that as well. We don't know when exactly the IP will be reached. Typically, in Area 1, we've seen anywhere from 1 week to 3 weeks with this latest generation of slickwater designs, it's not only the sand that goes up, it's the water you're pumping goes up. So you're getting a whole lot of water back as well. So managing that flow back and watching your water oil rates ratios and your water cuts, is all part of how we try to monitor and optimize that flow back. What we're seeing on the Lager looks completely different from what we've seen in Area 1, in terms of water ratios and water cuts. And we're seeing less water overall in -- the pressure is -- probably what we're excited about. We've seen in between 4,800 to 4,900 on flowing pressures, had a brief shut-in at 5,300 psi while we put on the production tree. We think there's -- that shows a lot, I think, about the prospectivity of Area 2, particularly in and around the Lager area, to have a lot of success with slickwater.

(Operator Instructions) Our next question comes from Dustin Tillman with Wells Fargo.

You mentioned production uplift in the offset wells on Kudu. Can you quantify that?

Well, what we've seen on the production uplift on all of our slickwater wells, not just the Kudu, which is pretty early. Since we've started this, there's probably -- I can -- there's been 8 pads that had offset wells within the unit or directly offset. And on 7 of those 8 pads, we've seen production uplift in those parent wells. In the Kudu, we had 1 well, the most direct offset, it's production went from about 40 barrels a day to 90 barrels a day. And whether or not that gets sustained remains to be seen. But that can give you the average of what we've seen over the other 8 pads, we've seen an average of about a 28 to 48 barrels a day over a year period, so it's sustained. It's not just an instantaneous rate. Does that help?

It does. Does that impact at all how you think about the placement of future wells?

Well, I think what it does is it gives us comfort that we're not going to be hurting the parent wells in the units. When we were doing things with the hybrid fracs, frac hits were typically negative. And so at this point, I think it's safe to say that we don't have that concern. We take steps to mitigate that, and we started doing that even with the hybrids by loading the offset wells with the field brine that effectively gives us a hydrostatic fluid column to push back against the offset wells that are being fracked. That mitigation does tend to help. And typically, these wells will unload a bunch of water and then start cutting oil and gas at a sustained rate for a period of time. So it's not something that is easy to predict on a quantified basis, but at least it gives us the comfort that we're not hurting the parent wells.

Yes, that make sense. Can you talk about just a broader M&A market in the Eagle Ford and what you're seeing opportunity set or interest-wise, in terms if focused interest in your assets?

Well, I think there's a variety of packages out there. We really like our assets, their high rate of return, that -- anything that we would look at, you would hope to find something that would have a similar rate of return, in adjacent properties are always preferable for us because one of our competitive advantages is having a big, blocky acreage position that allows us to get economies of scale and a compact footprint, drive our operating cost down and keep our logistics manageable. So I think we're really focused on what's in and around us. We've had some organic acreage pick up. We would like to extend that. Obviously, there's a finite amount of that out there, and prices tend to go up over time. So what we're focused on is really just maintaining that inventory as we drill the new wells. And we have the opportunity to add to it and it makes sense, then we will give that our full attention.

Our next question comes from Ben [Evers] with Black Maple capital.

You guys commented on your fourth quarter call that you were evaluating all strategic alternatives available to the company, can you provide us an update, please, on that matter?

Well, as part of our overall strategic review, we're looking at a wide range of options available to us at this time. And currently, we don't really have any update to provide you on that.

There are no further questions at this time. I would like to turn the call back over to Mr. Brooks for closing remarks.

All right, thanks, Michelle. Well, thanks for joining us on today's call, and we look forward to speaking with you again at our next quarterly call. Thanks.

Thank you. This concludes today's teleconference. You may disconnect your lines at this time. Thank you for your participation, and have a wonderful day.