PostRock Energy's (PSTR) CEO Terry Carter on Q2 2014 Results - Earnings Call Transcript

 |  About: PostRock Energy Corporation (PSTR)
by: SA Transcripts

PostRock Energy's (NASDAQ:PSTR)

Q2 2014 Results Earnings Conference Call

August 07, 2014, 11:00 a.m. ET


James Stewart – Senior Financial Analyst

Terry W. Carter – Chief Executive Officer, President

Casey Bigelow – Chief Accounting Officer


Welles Fitzpatrick – Johnson Rice


Good day, ladies and gentlemen, and welcome to the PostRock Energy Second Quarter 2014 Earnings Conference Call. At this time all participants are in a listen-only mode. Later we will conduct a question-and-answer session, and instructions will follow at that time. (Operator Instructions). As a reminder this conference call is being recorded.

I would like to introduce your host for today’s conference, Mr. James Stewart. Sir, you may begin.

James Stewart

Thank you, [Ben]. Good morning, everyone, and thank you for joining us today. With me are Terry Carter, our President and Chief Executive Officer; and Casey Bigelow, our Chief Accounting Officer.

Before we begin, you should know that our second quarter earnings release is available on our website at, and that our 10-Q will be made available on the website today or tomorrow.

Our remarks on today’s call may include forward-looking statements and assumptions that are not historical facts. We base these forward-looking statements on our current expectations and assumptions about future events. We caution you not to place undue reliance on these forward-looking statements as they are subject to risks and uncertainties that could cause actual results to be materially different from those currently anticipated.

Please read our full disclosure on forward-looking statements and risk factors in our filings with the SEC. Additionally, in the course of today’s call, we will refer to certain non-GAAP financial measures such as adjusted EBITDA, which we believe is an important metric for evaluating our performance. Be sure to see these reconciliations in our earnings release. Following our remarks, we’ll be available for questions.

I’ll now hand the call over to Terry Carter.

Terry Carter

Thank you everyone for on behalf of team here at PostRock. Appreciate, you joining us for our quarterly call. In a moment I’ll turn the call over to Casey Bigelow, our Chief Accounting Officer to review some details about our quarterly performance. And then I will – but first I will give a brief review of some highlights.

Also in the room with me today, although they won’t be speaking on the call, our Vice President of Operations, Clark Edwards, and our General Counsel and Vice President, Administration, Steve DeGiusti.

We’ve made some pretty good progress since we last spoke and particularly, very recently as we begin to bring couple of horizontals wells on production. As you saw from our release, we had record oil production in the quarter, but still relatively modest number. It’s the highest that we’ve seen, up 16% from the first quarter and our revenues generated by oil were $6.2 million also the highest as ever been and just shy of 30% of our total revenues.

The increase in oil production in the first quarter was driven predominantly by a very successful workover program that we initiated in March and continued on through May. Those workovers generally we’re going to cost around $300,000 each, a little less. And they generate incrementally 50 to 60 barrels of oil per day per well declining hyperbolically at about 40,000 barrels of incremental reserves each. They’ll generate rates of return in excess of 100%.

Probably, most important thing that we’ve done in a long time, we started drilling in late May the first two – the two horizontal wells at Searight field in Central Oklahoma. The first was brought on production in late June and thus far it looks to be the best well that PostRock has ever drilled that significantly exceeded our expectations.

It peaked recently at just over 600 barrels of oil per day. The second was brought on line a little later. It will probably be a few weeks before we know exactly where it’s going to peak. But it’s somewhere north of 100 barrels a day today, and we expected to increase until we know what the peak production really is and I’ll explain it little bit more as I speak in more detail about these wells later.

As we mentioned, a little bit during the last call, we’ve completed our compression reconfiguration project that came in at expected cost and was online by late May, completely online by late May. We still have a few minor things to do like moving some of the oil compressor’s office, the owners require them. But we are now recognizing the full savings and full savings of fuel which converts the sales and that’s one of the reasons why we have a lower percentage gas decline than what we’ve historically seen.

Finally, we entered into a 28 square mile JV. You may have seen the release earlier in the summer. The Silver Creek oil and gas for the purpose of initially testing the Woodford shale on some of the primary term acreage that we bought when we purchase the acquisition back in November of last year.

It’s an important JV for us because it allows us to do initial Woodford development test at a lower capital expenditure rate than we would have otherwise done. Silver Creek will operate the JV at 70% and we will own 30% of whatever the combined position is once drillings are complete.

The first two wells drill back-to-back should begin sometime next week. And I expect that the drill times on those will be somewhere between 15 and 20 days. Then they will both be completed some times in the fall.

I will go into a little bit more detail about all of these things here in just a few minutes, and -- but first I’ll turn this is over to Casey and let her go through financial performance information for the quarter.

Casey Bigelow

Thanks, Terry, and good morning everyone. As Terry mentioned, I’m going to cover just a few key financial numbers from the quarter. As I noted last quarter when I speak to production equivalents, I will be using our actual second quarter economic equivalency of 23:1.

If you’d like the see the traditional 6:1 energy equivalency for comparison purposes there is a good table on page four of our earnings release. Production on an economic equivalent basis was flat on quarter over the prior year quarter averaging 52.3 MMcfe per day.

Gas production averaged 36.7 MMcf a day, down 8.2% from the prior year period. This is an improvement from our traditional 11% to 13% decline on the quarter. The primary driver of the reduction is attributable to the fuel savings from the compressor optimization project that we wrapped in late May of this year coupled with a slight improvement in our overall decline curve for the period.

Oil production averaged 682 barrels a day on the quarter, a 25% increase over the prior-year period. Additionally oil contributed 29% of our revenues on a quarter compared to 23% in the 2013 year period.

Our production was flat on a quarter revenue totaling $21.6 million, was up 10% from the prior year quarter due to increased gas prices and increased oil production volumes and prices. Gas revenue increased 1.5% to $14.7 million as our average realized prices increased to $430 per [M] from $397 per M in the same quarter last year.

Oil revenue increased 39% to $6.2 million on a quarter due to the 25% increase in production volumes, as well as increased in realized prices to 99.82 a barrel from 89.81 a barrel last year. Gathering revenue increased 4.2% on a quarter also due to higher prices.

Production costs, which include LOE gathering and production taxes totaled $10.6 million for the quarter and were down 1% over the same period last year. The largest driver of the decrease was reductions in labor and gathering costs in the Cherokee Basin of $900,000, primarily resulting from a compressor optimization project.

These reductions were partially offset by higher operating costs in Central Oklahoma as we more than doubled our [well comps] in the area over the last year as well as realized a significant increase in fluid production levels in the area.

On our equivalent basis, over the past two years our per unit cost in Central Oklahoma has fallen from 37.82 per BOE to 25.17 per BOE in the current quarter. Reductions, we expect to continue as we further develop out the area.

G&A totaling $3.5 million for the quarter was down 17.8% or $758,000 on a quarter from a prior year period. This reduction includes a $528,000 workman’s comp charge in 2013 that we obviously didn’t incur in 2014. If you exclude this charge from the prior year period G&A decreased 6% on the quarter.

The decrease in G&A was primarily driven by lower non-cash comp in the currently year period. We don’t expect to see any appreciable changes to our G&A costs throughout the balance of the year. Through June we’ve spent $17.5 million on capital projects, down 38.3% from the first half of 2013, as we performed fewer projects in the first six months of this year.

Starting in the latter part of the first quarter through June, we spend approximately $3 million on the 12 development workovers as Terry mentioned in Central Oklahoma, all of which are projected to have returns of greater than 100%.

Today, we’ve spend a combined total of $6.2 million on drilling and completing our two horizontal wells in Central Oklahoma of which $4.3 million of this spend fell into the second quarter. We spend $4.8 million through June on maintenance projects primarily the compressor reconfiguration project that was wrapped up in late May. And finally we spend $1.1 million on geological and geophysical cost in Central Oklahoma primarily related to the licensing of seismic data on the acreage we required in November of last year.

We expect to invest an additional $14 million to $15 million throughout the balance of the year on capital development, almost completely funded by cash flow from operations. We realized losses on our hedges in the first six months of the year of $4.4 million compared to $2.2 million in the prior year period. The increase was due to increased pricing year-over-year.

We recognized mark-to-market losses on our derivative contracts of $3.5 million for the six months ended June of this year, versus gains in the same period, gains of $3.9 million in the same period last year. Our natural gas and crude oil swaps cover an average of approximately 28 MMcf per day and 315 barrels per day for remainder of the year at weighted average prices of 4.01 per M and $95.19 per barrel. Our current prices we expect to recognize $130,000 in gains on our hedges throughout the remaining balance of the year.

Finally, we recognized mark-to-market gains on our CEP investments of $1.7 million in the current year period versus $4.4 million in the first six months of last year. On March 31, we settled our CEP lawsuit for a total target recovery of $21.6 million, at settlement we surrendered all of our Class A units and sold $1 million or 415,000 B units for an initial recovery of $8.3 million.

Since the initial recovery in the second quarter to-date we’ve sold additional $2.3 million B units for total proceeds of $6 million through the end of July, at which we had $3.2 million B units remaining to sell, which we held for sell before the end of the year, but realized sales could run into 2015.

We ended the quarter with $87 million borrowed on the borrowing base, down $8 million from the end of the first quarter, despite also funding our development program for the first half of the year, utilizing cash from operations and CEP proceeds, we were able to decrease that by another $2.5 million in July, ending July at $84.5 borrowed on the borrowing base. Under current prices we expect to see our debt to continue to drop as we go through the balance of the year.

At June 30, the liquidation value on our Series A preferred stock was $109 million. Subsequent to the end of the quarter, the company might be agree to extend the date through which we may accrue dividends on these preferred rather than pay them in cash by 18 months through the second quarter of 2016.

And with that, I’ll hand it back over to Terry.

Terry Carter

Thank you, Casey. Just a bit we have when we went to this year. And I’ll just review those real quickly at least some of them and give you a sense for where we are on accomplishing those objectives. As we’d mentioned earlier, we had an objective to grow our oil production quarter-to-quarter. Again growing quarter-to-quarter on a consistent basis, and also elevate some of the historic decline that we have in natural gas primarily in the Cherokee Basin.

We also had an objective to complete our compression project at or under cost. And we had an objective to drill multiple horizontal wells, four to five of them this year targeting both the Hunton and the Woodford, the Woodford shale in the region.

There are few other things like improving our technical capability and beginning to address securing additional opportunities outside of our current leasehold position that we’ve been working on as well.

As you could see from our press release, our current production, because of the wells that I mentioned earlier that we’ve drilled – was over 900 barrels a day as a matter of fact, I think the first six days of August our estimated production rate is just north of 1,000 barrels a day. I’d expect that the decline is – these wells modulate decline as per the peak production rates over time.

But much more robust and what we had anticipated in our plan. I’ll talk a little bit first of all about the horizontal wells. The two wells that we drilled, we’ll just call them the 5-1 and the 5-2, we’re drill in Searight field, the 4-1 and the 5-2.

Drill in Searight field in Seminole County, Oklahoma, the first one, the 4-1, had a lateral length of between 2500 and 2600 feet and frac it with nine different fracs stages. The second one was slightly longer just over 3,000 feet and we frac it with 11 fracs stages.

As a typical frac stage -- this is a carbonate as oppose to the shale and so the design on the frac stages are little different than it would might be traditional. Its around 10,000 barrels of water, around 10,000 gallons of hydrochloric acid and some additives and around 25,000 barrels of sand.

That really a typical type reservoir like you might be use hearing about on – when people talk about shales and ultra-type horizontal drilling. Our expectation here was looking at the field and an analyzing it, we felt that this field was originally developed back in the 30s and have produced since that time pretty much continuously.

Our analysis indicated that there should be significant remaining oil in place and the interesting thing about lot of these old carbonates is they have multiple storage regimes. They have multiple permeability regimes and comport mineralization, its pretty significant. We thought we could overcome that with horizontal drilling.

It has high water cut typically at somewhere in axis of 95% on average basis. When we drill – we drilled our first well to test this idea and we also did workovers to help understand the impact of modern day completion technique and that all prove to be very successful.

So, we initiated a new drilling program this year to begin to flush that out with some of the learning’s that we had from last year. Obviously the 4-1 well has greatly exceeded our expectations, and in fact its peak product rate to-date has exceeded the actual expectations for the combined peak rates of both wells. And so it’s really put a charge in our oil production rate and maybe what our expectations are for the future.

The second well is not performed as well. We looked at it recently on just a common day trying to normalize the two wells to the same time period. And it looks like in the same time period; the peak production for the second well as well as the load recovery rate was roughly two-thirds or little less of the 4-1.

So I doubt that that’s going to be a significantly well, but it’s a little bit early to tell. More recently our fluid rates have began to increase, which is a good sign. We still haven’t been able to effectively draw the well down. It will likely be at least ten days to two weeks before we have a good handle on what our peak rate is going to be on the second well.

Our combined daily production on those two wells is still between 630 and 640 barrels a day. So, pretty exceptional wells for our company, very meaningful. Typically these wells will come on production and because of the high water saturation that exists in the reservoir and in certain areas. It will take 30 to 40 days before we really reach a peak production rate that we can actually see as the ultimate peak.

And that means we recover enough water back to effectively equal about 100%, 90% to 100% of our load. As I said, it’s a real meaningful thing for us not just on our current expectations for oil production growth as we go through this year, but we think we have somewhere between 6 and 12 or 12 plus additional locations on the two fields that we operate there ranging anywhere on working interest from 25% to 100%.

The wide range and potential prospects on our current acreage is really depend on obviously existing performance on the wells that we’ve drilled today, but also ultimate spacing. We don’t really know exactly what the spacing going to be. We’ve made some assumptions that it’s going to be one well for 320 acres, but it could actually be more than one well for 320 acres.

There are obviously other old field Hunton development opportunities that we’ll be looking at as well. And there are other potential horizons at Searight field in particular in the Pennsylvanian section and in the oil division section that we’ve not really addressed yet, as we’ve been focused on the large target which is the Hunton. We will be doing those kinds of things probably over the next year.

Finally the WoodFord JV, what makes this meaningful to us is when we purchased the acquisition last November, and some of it in southern Pottawatomie County, we knew that the Woodford was significant in thickness and approximately a developable depths there, but it had not been addressed any significant way.

We acquired 22,000 acres, 8,000 of which was HBP as I’d mentioned. And we started looking for a partner, because we really didn’t think that we wanted to [stomach] the full capital risk. We thought that it’s going to take somewhere between four and six wells to effectively test.

Those wells are going to cost in excess of $3 million. So we look for a partner that was summary focus to us, but also had a great deal of more experience than we did and could really help us with that process. And we’re fortunate to find Silver Creek, which is Texas Company who essentially was acting on the same idea that we were.

And we finalized this JV order in the year. As I mentioned earlier the first well probably spud next week. This is a pretty meaningful deal, because if you just look at the section that we have ownership in, if the Woodford to be successful, it would mean literally 100s of wells potentially that could be drilled over time.

As we go through the rest of this year, what our expectations, pretty much to accomplish the things that we said out to do when we talk in first quarter. We expect to drill at least one maybe two additional Hunton wells, just rig availability and preparation to drill and watching the performance of the first two wells for a little while we would not expect to spud the next Hunton well until late third quarter, early fourth quarter.

And its possible that we could drill two wells back to back again, so the second well would obviously would not have a meaningful impact on fourth quarter production. We’re going to drill two wells as a part of the JV, Woodford targeted. Those wells are again will likely come on some time in the fall, September, October time frame.

The way that silver Creek expects to drill those wells is they’ll drill them back-to-back and then they will install all of the required facilities for operations and then they will complete them back-to-back at the same – under the same manner.

We also expect to participate in either as a non-operator or possible as a operator in one to two other Woodford wells in the balance of the year, probably at less than 50% operating ownership and one of them probably less than 10%.

All-in-all, as Casey mentioned earlier our expected capital plan for the balance of this year is somewhere between $14 million and $15 million. And with current prices and expectations we would expect to fund our development from this point forward out of cash flow, which means that essentially all of the proceeds that we would get from the incremental sale of CEP unit will go to retire our bank debt, and so we would expect to see our debt trend down whereas we through the fall and up to the end of the year. Right now, we’d expect that level at then end of the year would be somewhere in the $80 million or maybe slightly less range.

So, overall I think we’ve had a great – we’ve had a great four plus months when you add in the success that we seem to have had thus far on the drilling. It’s pretty exciting for our company to begin drilling wells that make an excess of 5,000 barrels of oil a day. Obviously it just the start for us, but I think it’s a very good start.

With that, I will turn it over to anyone who might have a question.

Question-and-Answer Session


Thank you ladies and gentlemen. (Operator Instructions) Our first question comes from Welles Fitzpatrick at Johnson Rice. Your line is open.

Welles Fitzpatrick - Johnson Rice

Good morning. Obviously the 600 is well above your type curve, which is – I think its somewhere around 200, if I’m remembering correctly?

Terry Carter

That’s correct.

Welles Fitzpatrick - Johnson Rice

The cost seem it touch higher too, can maybe you let us know where you’re thinking this will end up cost wise? I mean is that 2-3 to 2-5 is that more of a longer term kind of development mode type well costs, and where you think the IRR is might kind of end up on – I mean I guess that well specifically for now?

Terry Carter

Well on that well, the IRR is obviously going to be very good. Frankly, we probably under estimated the cost that we were going to incur as we drill these wells. So we had problems in drilling it completion, but not really material – my expectation is that we’re probably going to go forward with somewhere in the neighborhood of 3 to 3-1, somewhere in that range for expectation, depending on the lateral length.

If we begin to extend the lateral lengths out a little bit longer, those costs could go up a little bit. Just based on what we’ve seen to-date, the likelihood is that we’ll begin to work on as we gain experience some of the front end cost for drilling and also modulate a little bit our completion techniques to drive those costs down.

But I think for modeling purposes it’s probably safe to assume about $3 million or $3.1 million well. That was about 15% over what our AFE was, and we AFE these wells early in the year. As far the rate of return, we actually haven’t remodeled these wells because we want to wait until we had a little bit of a decline basis once they had peaked.

But if you just look at the combined total of those two wells, currently I just said that this is good as its going to get. The payout that I calculated just on the back of the envelop earlier was going to be somewhere in the neighborhood of 1.2 to 1.5 year, which would seem to indicate a rate of return well on excess of 50%. So I think that’s a fairly safe number to use. We’ll have a lot more information by the time we speak again, because we’ll have 90 to 120 days – 90 to 100 days of actual experience producing them.

Welles Fitzpatrick - Johnson Rice

That’s great. And I know it’s not [indiscernible] which remain to the economies of the wells, but what was the associated gas on those kind where you thought to be anything of no going on there?

Terry Carter

As you know, because this is an old water injection field, one time it’s going to be a water flood. There is not a tremendous amount of associated gas. I think our total associated gas Clark right now is, about a half a million or less, little less than a half a million a day on the total. So, there’s not a significant amount of value in the associated gas with these wells. It’s pretty much black oil.

Welles Fitzpatrick - Johnson Rice

Got you, got you, perfect. And then on the LOE, we just modeling that going forward, how do you see that – I mean, it seems like your compressor optimization projects would have come in to a close. I mean, I know some of its ongoing, but the major push? And then you have obviously some areas, how do you see that kind of trending through year end?

Terry Carter

Okay. Let me give this regionally, okay. And right now our gas production in the Cherokee Basin on a net basis is somewhere between $36 and $36.5 million a day of natural gas and we expect the results of things that we’ve done to-date to sort of begin to drive our operating cost down to something less than our gross cost including that cost that we use of capital that ends up on our capital line be something less than $2 probably in the $80 to $75 range, like $75, $80, it that about right, Clark.

And Casey mentioned earlier our expectations in Central Oklahoma is that we’re currently in the $25, $24, $25 of barrel range, down significantly from what was a year ago, year and a half ago, and we would expect that to fall further as our production volumes increase going to forward to something in a neighborhood of $20 to $22 a barrel is reasonable safe model I think.

Welles Fitzpatrick - Johnson Rice

Okay. That’s perfect.

Terry Carter

As we drive that production rate up that expectation of cost will come down a little bit more. But in Searight field proper because we handle so much water. There was sort of the flow there somewhere that’s probably not much below $20 barrels.

Welles Fitzpatrick - Johnson Rice

Great. Thank you and congrats on the good quarter and the great well.

Terry Carter



Thank you. (Operator Instructions) At this time, I see no further questions in queue. I’d like to turn the call back over to you, sir.

Terry Carter

Okay. Well, we thank you again for joining us. And we look forward to having a fairly substantial improvement to our oil volumes in the third quarter versus the second quarter, and beginning to have on an economic basis meaningful growth on total volume as we go through the rest of this year.

So, we should begin to see year-over-year growth third quarter, fourth quarter and hopeful we’ll be able to continue that as we accelerate our development on into next year. So appreciate you’ll join us and look forward to talking to you next quarter and hopefully we’ll have more good news to share with you by then. Thank you.


Ladies and gentlemen, thank you for participating in today’s conference. This does conclude your program. You may all disconnect. Everyone have a great day.

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