Replies to This Discussion

Permalink Reply by Philip Brutz on March 5, 2015 at 9:04am

Permalink Reply by Jan on March 5, 2015 at 9:19am

Waiting pipelines - is that Scott & Yontz?  

Deferred completions - Finneran? Names of others to the west?

Permalink Reply by David Allen Lilly on March 5, 2015 at 11:52am

Go to page 4 of the presentation,

"Joint venture process underway(2)
–
JV to accelerate drilling activity without negative impact on liquidity and potentially provide opportunistic acquisition capital"

But, note2,

" There can be no assurance that Eclipse Resources will be successful in closing such a transaction or the terms or timing of any such transaction."

Permalink Reply by David Allen Lilly on March 5, 2015 at 11:53am

So, I feel more strongly now that Eclipse will get some of these units drilled here in my area this year, especially if the pads are already built, and they will do them in a joint venture.

Permalink Reply by Philip Brutz on March 5, 2015 at 1:49pm

Excerpts from  Eclipse Resources' (ECR) CEO Benjamin Hulburt on Q4 2014 Results - Earnings Call Transcript.

Complete transcript here: http://seekingalpha.com/article/2977716-eclipse-resources-ecr-ceo-b...

Going to slide 6, our operated production base at year-end consisted of 21 condensate wells, 7 dry gas wells and one Marcellus well, with 28 of the 29 wells turned to sales during 2014. During the fourth quarter we turned the Fritz, Hayes and Pora pad to sales all in the condensate band of our acreage. These pads include 11 wells with average lateral lengths of approximately 7100 feet. All of these wells are being produced on a restricted choke to preserve reservoir pressure. And although initial indications are positive, we experienced numerous midstream issues during the quarter associated with the delayed start-up of Blue Racer’s burn plant, operational issues at Natrium as well as pipeline related issues dealing with hydrates and excessive liquids.

All of which were exacerbated due to the extreme cold temperatures. As Ben mentioned, we are currently operating one rig in the Utica shale dry gas area. This rig is currently drilling on our three well Shroyer’s pad on reduced inter-lateral well spacing of 750 feet. This pad is approximately 6 miles south-west of our Shroyer pad which in the fourth quarter of 2014 included the top two producing gas wells in the state of Ohio according to state production data.

We’ve completed the drilling of the first two wells on the Shroyer pad with an average spud to TD of just 19 days and are commencing the third well in the coming week. This average drilling time is superb when compared to our original estimation last year during our IPO process which called for drilling times in the dry gas area of approximately 30 days to drill a 6000 foot lateral. This pad is an exciting test for us as it will be our first dry gas spacing test. While historically we’ve drilled dry gas wells at a 1000-foot inter-lateral spacing, this pad is being drilled on 750 foot inter-lateral spacing.

To the extent, this reduced inter-lateral spacing proves to be economic, it could increase our estimated dry gas well locations by over 25% on our current acreage position.

Moving to slide 7, as of March 1, 2015 we had 6 gross operated wells drilling, five of which were being top [indiscernible], one well waiting on completion in 2015 and 25 or 19.3 net wells accounting for 765 gross stages currently delayed for completion. We also were participating at 41 non-operated wells in progress. From the map you can see that the deferred completion activity is largely concentrated in our condensate and rich gas type curve areas and our drilling activity is focused in our dry gas type curve area.

Neal Dingmann - SunTrust Robinson Humphrey

Second question, Ben for probably for you or Tom. I noticed now on, I think the wells that you now put up kind of to date versus the first quarter, I think the IP rate or the 24-hour peak rate was pretty similar. But I noticed on the new batch, you know the average has now improved on the 30-day average. So I guess my question is, is there you know anything different that you all are doing on you know chokes program or anything like that? Or it just happen to be where these wells are located?

Benjamin Hulburt - Chairman, President and Chief Executive Officer

Yeah Neal, there isn't from what we can tell any significant variance in what we think the long-term performance of the wells are in this last batch versus the ones we announced previously. The production rates that are reported in the earnings release have been affected by several midstream related issues that Tom alluded to, dealing to a large extent with the start-up of Blue Racer’s new cryogenic processing facilities called the burn plant, with some down times that we experienced at Blue Racer’s Natrium facilities.

And then the startup of our condensate stabilization facilities, which we are in the process of turning over to EnLink. So a variety of those circumstances impacted production at certain pads during different periods. We have an internal production target for these wells using our restricted choke methodology, and we managed the choke to attempt to hit those targets. So, but at this point, there isn't a large variance in what we think the ultimate EUR is in any of the wells. All appear to be in line with our type curves.

Holly Stewart - Howard Weil

Just a couple of questions here. Maybe first, I guess Ben it sounds like you're going to move forward until you reach an agreement with sort of that half CapEx number that you initially threw out there in one rig. So should we anticipate that rig just kind of moving forward in Monroe County drilling dry gas wells?

Benjamin Hulburt - Chairman, President and Chief Executive Officer

Yes, for the time being our plan involves keeping that rig in some of our deepest, highest pressured areas of the dry gas bands. However I’d like to point out, I mean one of the advantages of our asset base is over the course, a span of a county and a half, we can move our rig or rigs all the way from heavy condensate yield wells to some of the best dry gas wells in the country. And we’ve pads and title done in basically every one of those bands.

So our current plan is to keep that rig in the highest pressure dry gas areas where we still pretty attractive returns. However, if we see a liquids price improvement which could happen fairly rapidly, we would then react to moving that rig back toward the liquids area and the condensate areas where we’ve several units ready to go and actually even several of the pads that are built and constructed. So you will see us react to the commodity price as it moves throughout the year.

Holly Stewart - Howard Weil

But if you stay in that dry gas window, will that rig be in Monroe or Belmont?

Benjamin Hulburt - Chairman, President and Chief Executive Officer

Predominantly Monroe. We’ve a couple of units that are possible to drill into the Belmont area, but predominantly in the northeastern corner of Monroe County.

not a permanent situation.

Operator

Thank you. Our next question comes from the line of Leo Mariani at RBC Capital Markets. Please proceed with your question.

Leo Mariani - RBC Capital Markets

Hey guys, obviously you spoke about being nimble with the rigs and you got a pretty good backlog of completions in the [conde] window. I am sure you are somewhat waiting for costs to fall here, but could you give us a sense that you know what type of you know oil price you would like to see before you start completing some of that backlog of wells or moving the rig? Is it 60 to 70, could you kind of give us any thoughts there?

Benjamin Hulburt - Chairman, President and Chief Executive Officer

Sure, Leo. And it's not just an oil price move because they do still produce gas and we also have to watch where the NGL realization is. But I would say simplistically as the WTI price gets closer to $65 to $70, that's where we would probably look to put more capital to work into that area.

Leo Mariani - RBC Capital Markets

Okay, that's helpful here and I guess obviously you know JV discussions sound like they are still in process. I mean can you layout any type of you know high level timeframe as to when you think something may get resolved? Is it sort of midyear? Is it kind of second half, just anything like that you can help us with?

Benjamin Hulburt - Chairman, President and Chief Executive Officer

Sure, I mean our objective is to complete these negotiations in the next 30 days. Now closing on transactions, joint-venture transactions and documentation can be quite complicated. So I wouldn’t close that quickly, but our objective is to complete the discussions and start drafting definite documents in the next 30 days. And at that point, we could probably update the market with some initial thoughts both on the JV structure as well as what we think our capital budget will ultimately be over the course of the year. So I would expect to be able to update the market in the next 2 to 3 months.

Leo Mariani - RBC Capital Markets

And I guess you also made some comments that you know part of the motivation in the JV maybe to take advantage of some opportunities and you know what are you guys seeing out there in terms of you know available acreage here?

Benjamin Hulburt - Chairman, President and Chief Executive Officer

I probably don't want to go too much into that, no brain surgery here. But I mean it's our belief that given the downturn, there will be several opportunities to acquire acreage in our core focus area of Southeast Ohio, Northwest West Virginia, Southwest Pennsylvania. As far as what prices are obviously to the extent we do acquire acreage with the intent of doing it opportunistically at prices there are substantially below what acreage prices were a year ago.

If it doesn't materialize that asset prices have fallen, then we would not pursue that strategy. The whole intent of it is to really be opportunistic and add core assets while prices are down. If that theory doesn’t prove correct, then we will just continue to focus on our current assets rather than just buy assets, just to buy assets.

Leo Mariani - RBC Capital Markets

I guess just lastly, is there any update on any of the kind of you know leasehold issues you had around the Oxford acquisition?

Benjamin Hulburt - Chairman, President and Chief Executive Officer

No, I guess as time goes on and given what’s happened in some of the courts of other cases, we feel more and more comfortable about it. But we haven't as a company had any updates on our own issue.

Operator

Thank you. Our next question comes from the line of Subash Chandra with Guggenheim. Please proceed with your question.

Subash Chandra - Guggenheim Securities

If you can remind me, what is the leases expiring in 2015?

Benjamin Hulburt - Chairman, President and Chief Executive Officer

Off the top of my head, Subash the leases expiring in 2015 are under a 1000 acres and pretty much the same in 2016. We really don't have any acreage of any magnitude expiring until 2017. And acreage that does come up for expiration in 2017 would all have five-year extension rates after that.

Thomas Liberatore - Executive Vice President and Chief Operating Officer

And additionally most of that acreage that would come up is in that dry gas area where we’re active currently.

Subash Chandra - Guggenheim Securities

Yeah, okay so not an issue at all. And I don't know your comfort to talk more on the fundraising or I should say the joint-venture or are you thinking about it at sort of the corporate level? Or are you thinking about asset carve-outs to where you know it’s an investment by that financial partner in a particular subset of your acreage? Or you think about it as a way to accelerate I guess the dry gas until commodity prices improve?

Benjamin Hulburt - Chairman, President and Chief Executive Officer

I guess, I can say at this point it’s not corporate focus and our objective is to keep it as close to wellbore focused as possible.

Subash Chandra - Guggenheim Securities

Okay, could you comment whether then this would be you know the wet gas area or the [conde] area that you would seek to accelerate or revive?

Benjamin Hulburt - Chairman, President and Chief Executive Officer

I really can't at this point. It most likely will follow our drilling plans, whether that's in the dry gas area or the condensate.

Ipsit Mohanty - GMP Securities

And I thought you said something like $65 or $70 oil to put rigs back in work in the condensate? I was wondering sort of what level of service cost reduction or commodity price will it take for you to at least complete the well, the condensate wells that you’ve a backlog currently?

Benjamin Hulburt - Chairman, President and Chief Executive Officer

Well when I said we would put, go back to work in the oil window or the condensate window at $65 or $70, I think what I said is that’s when we would start putting more capital to work, not necessarily that we would add rigs right away in that band. So $65 to $70 oil is probably where we would decide to start playing capital into there. And undoubtedly the first capital we spend will be on completing the wells that are deferred completions. So that would be the first step and I think if we see oil prices stay in that area for a period of time, that's when we would look to start bringing back additional rigs.

Ipsit Mohanty - GMP Securities

And so nothing dependent on service cost reductions of any?

Benjamin Hulburt - Chairman, President and Chief Executive Officer

No, I would say we are in the process of locking down service cost reductions as long as we can. But to the extent we can for example if we locked in pumping services on our frac stages, they would be substantially lower than that we’ve seen historically. However they won’t be permanent. So as commodity prices go back up, I would expect to see service costs creep back up. So it's tough to make a multi-year decision based solely on that. It's a great benefit and it's very helpful while commodity prices are down. But certainly it’s a variable cost and you know we try to frame the business on a multi-year strategy. So it's not something that we can forecast forever.

Ipsit Mohanty - GMP Securities

And then I think the last call around you had talked about a greater comfort and the infrastructure around the wet gas and condensate areas versus dry gas because at that time, you had deemed it right to focus there. And now that you're switching to the dry gas, are you more comfortable with the infrastructure set up, the midstream set up around the areas you're drilling?

Benjamin Hulburt - Chairman, President and Chief Executive Officer

I would say at this point, both our dry gas and our liquids area have substantially complete infrastructure. Most of our dry gas acreage is going into the Eureka Hunter system which is the trunk line of which is already all complete, runs through our acreage and has connected to Texas Eastern and REX and we built our own connection into the Dominion system. So in that area, a large part of our infrastructure is already in place. In the liquids area, most of the pipeline was there. The condensate stabilization facilities that we built, they are substantially already in operation or substantially complete.

Our gas is processed by Blue Racer, our operated gas, either at the Natrium II facility or at the burn plant. The burn plant did experience several delays and some challenges during its start up. However with those facilities now up and running, I would weight our risk to midstream relatively equally between the two areas, because it’s substantially complete in both the dry gas and the liquids area.

David Deckelbaum - KeyBanc Capital Markets

You know first I guess, you know a lot of people have asked a lot of questions about the JV. But I think, you made a point in the slide deck that do you see the primary goal of the JV to reaccelerate here and I guess does that -- you know how much acceleration is being considered? Is it getting back to the original plan such that you wouldn’t be cutting from three to one rig? Would you go back to three rigs with the right financing partner? Because then that would protect the liquidity that you have, how are you guys thinking about that in terms of acceleration?

Benjamin Hulburt - Chairman, President and Chief Executive Officer

Sure I think the answer is that regardless of whether we have a JV partner or not, we are still going to judge our decisions on when to drill more of our acreage based on what we think the returns of the wells are. And the point of the JV is potentially to bring in a capital that's lower than our own cost of capital and provide leverage and greater well returns. So to the extent that's true, it would allow us to accelerate and achieve greater returns.

However if commodity prices are still very low, we are still not going to go out and add a bunch of rigs and drill up and produce our depleting asset base. That doesn't seem like the best decision over the long term, regardless of whose capital you're using to do it. The point of the JV is to continue at this pace while using less of our own capital, keeping our own dry powder as large and as long as possible. And to accelerate when we see commodity prices that dictate us to accelerate, regardless of whether that's JV capital or not.

The structures that we are discussing with JV partners certainly allow for that acceleration and I think both parties would welcome that. But we are really focused on what's the best long-term strategy for the company. We continue to believe we have one of the best acreage positions and one of the best plays in the country. And it continues to be our belief that it doesn't make a lot of sense to sell all your oil and gas and accelerate in a time when prices are very low, unless you believe those prices are going to say that low for a long time which in our opinion they aren’t going to. So hopefully that answers your question.

David Deckelbaum - KeyBanc Capital Markets

Yeah, I guess there’s a lot of moving pieces. But it sounds like we will have some answers in the next couple of months. Matt, I think you responded to a previous question that you could see the mix being 65% gas in 2015. Does that contemplate that you guys just complete the current conde wells that are in process for completion? And then you know how many dry gas completions are added on top of that?

Matthew DeNezza - Executive Vice President and Chief Financial Officer

It basically assumes, we don't complete the wet gas or condensate wells that are currently being deferred. And it assumes we basically complete an inventory of you know wells that are ready to go based on that dry gas activity from the one rig. So off the top of my head that's probably on the order of 12 wells over the course of the year.

David Deckelbaum - KeyBanc Capital Markets

And do you know what the average lateral length you intend to drill on those dry gas wells are?

Thomas Liberatore - Executive Vice President and Chief Operating Officer

I think our average for the year is in the 7300 foot range.

Benjamin Hulburt - Chairman, President and Chief Executive Officer

Yeah right around 7000 feet, David.

David Deckelbaum - KeyBanc Capital Markets

And the last one that I have is just more on geology, Tom maybe. You know you observed meaningful differences between the Harrison condensate acreage versus you know sort of the East Guernsey area? It seems like the well performance at least from the last batch of you know the Mizer Farms wells relative to some of the recent completions that seems you know fairly consistent?

Thomas Liberatore - Executive Vice President and Chief Operating Officer

I think on the geological standpoint, you know our analysis in high-grading acreage is that moving north into Harrison County, about halfway through the county we believe you're still in the core area. And our Mizer Farms bed is really right on the line, where we think you leave the core area. They are materially different than what we’ve seen in Eastern Guernsey. I’d say the one thing that changed from our initial expectations were our thermo maturity bands which we have updated and we will update in the next presentation we put out.

We shifted slightly, I would say to the east making Mizer County area or the Harrison County Mizer pads slightly more liquids rich than we originally estimated. But other than that, we haven't seen a material difference between the Mizer pad in the Eastern Guernsey County. It would be our expectation that going any farther north, then that Mizer pad we would start to see a drop off in the performance.

Permalink Reply by Jan on March 5, 2015 at 2:20pm

Thank you, Phillip for posting this.  Very interesting.

Division Orders for the Frank Miller Unit have arrived!

Permalink Reply by David Allen Lilly on March 6, 2015 at 1:56am

I am thrilled with the discussion concerning the joint ventures. Hopefully these joint ventures will allow the companies to share the cost of drilling making the wells profitable at these lower oil prices.

It kinda sounds like that is one way that Eclipse is looking at the joint venture option.

Permalink Reply by scott peterson on March 6, 2015 at 2:35am

Congrats Jan!

Permalink Reply by Philip Brutz on March 6, 2015 at 5:39am

http://seekingalpha.com/article/2976346-eclipse-resources-more-down...

Eclipse Resources - More Downside Ahead, Despite Fresh Capital Raise
Mar. 5, 2015 10:56 AM ET | About: Eclipse Resources (ECR)
Disclosure: The author has no positions in any stocks mentioned, but may initiate a short position in ECR over the next 72 hours. (More...)
Summary

Eclipse Resources reports big losses in the fourth quarter already.
Given that oil and gas prices have only slumped further, losses will only increase at current levels.
The massive equity issue and cut in capital budget expenditures provide some relief in the short term.
Despite a recent equity issuance, leverage could become a concern later in the cycle amidst a high cash burn rate.
Given the still large equity valuation in relation to the proven reserves, I remain extremely cautious and even bearish on the shares.

Investors in Eclipse Resources (NYSE:ECR) continue to be burnt as the company continues to lose a great deal of cash. While a recent equity raise has alleviated some leverage concerns, cash will continue to flow out of the door at the current trajectory.

Given these observations, very high break-even costs and the fact that the reserve base is relatively small I continue to be very cautious and have a negative stance on the shares.

Fourth Quarter Highlights

Eclipse Resources produced 123,800 Mcfe per day for the final quarter, as production increased by more than tenfold compared to the year before. In terms of oil-equivalent production this comes down to roughly 20,600 barrels per day. Nearly 75% of this production takes place in the form of natural gas wit NGL and gas making up the remainder.

Production revenues for the quarter came in at $50.4 million excluding a $19.7 million hedge gain. The trouble is that the company reported total costs of $101 million for the quarter including a $30.2 million impairment charge. Regular production costs came in at around $71 million resulting in a $20 million operating loss already, at a time when oil and gas prices held up relatively well.

This resulted in operating losses on top of which the company had to pay $13 million in interest expenses, for a net loss based on adjusted metrics of $33 million. Depreciation charges totaled some $37 million resulting in EBITDA of just $4 million.

Pro Forma Impact

Eclipse realized average natural gas prices of $3.37 per Mcf for the fourth quarter, excluding hedge gains. Ever since prices for natural gas have fallen to $.275 per Mcf based on benchmark pricing. Eclipse appears to be selling its gas at a discount compared to benchmark prices in the fourth quarter, implying that realizations could fall even further.

Applying a 30% discount to the current revenue base and revenues come in at just $35 million per quarter. Based on operating costs of $70 million and taking into account interest expenses, the company might be losing up to $50 million per quarter. EBITDA is actually seen negative based on these assumptions.

Note that this simplistic analysis is based on fourth quarter production levels, and while production might increase and interest payments might drop following a recent equity raise, the earnings picture remains far from rosy in my eyes.

Valuation, Balance Sheet And Reserves

Eclipse ended the quarter with just $67.5 million in cash and equivalents while the company had $414.0 million in debt outstanding. The $346 million net debt load is very large for the firm in relative terms. This follows the fact that the company is posting steep losses and negative EBITDA, while production remains relatively small.

To combat this situation, Eclipse has issued 62.5 million shares in January. The net proceeds of $434 million translate in to a modest net cash position of roughly $90 million based on the pro-forma results. Following this equity raise Eclipse has some 222 million shares outstanding which at $7 per share value equity in the business at $1.55 billion, or at around $1.45 billion excluding the modest net cash holdings.

Proven reserves came in at 356 billion cubic feet at the end of the quarter with a ¨PV-10¨ valuation estimate of just $510 million. This is just tiny compared to the current valuation.

2015 Plans, More Cash Outflows Foreseen

In 2014, Eclipse spend an unprecedented $809 million in capital expenditures, a huge amount for a company with such a size. For 2015 the company anticipates to cut this amount by roughly in half, supported by the cash being raised recently.

In the January presentation, Eclipse guided for production of 250,000-285,000 MMcfe per day, roughly twice the current revenue rate. On top of that the company guided for liquids production of 40% of total production, up from 25% at the current times.

This could result in the value of production increasing by roughly 3 times, although prices will fall of course big time versus the fourth quarter. It should be noted that this 2015 production guidance was based on anticipated capital expenditures of $640 million. By now the company has cut the size of the plan to some $400 million by now. Given the current deprecation charges which runs at $37 million per quarter, or $150 million per year, Eclipse will still see net investment cash outflows of potentially $200 million this year.

Add to that the fact that losses come in around $200 million per annum based on the current prices. While production will grow, it is unlikely that this will limit losses in a big way. Combined with the investment net cash outflows, I can still see Eclipse losing $400 million in cash this year.

Concluding Remarks

Eclipse is a total no go area for me. The reasons are quite simple. Unlike the vast majority of its competitors, Eclipse already posted large losses in the fourth quarter, at a time when many competitors were still posting profits. Worse, EBITDA was essentially flat in the fourth quarter which is quite disappointment.

The only bright spot is the fact that the company net holds cash at the moment following a colossal equity raise in January, alleviating bankruptcy concerns. The only trouble is cash continues to flow out at an aggressive pace as the company will run up a net debt load throughout the year at the current times.

Based on these observations and the fact that the enterprise valuation is roughly 3 times the present value of reserves, I remain extremely cautious. As a matter of fact depending on the cost of borrowing, I might initiate a short position in the stock.

Permalink Reply by Philip Brutz on March 6, 2015 at 6:28am

If they do go bankrupt another company will take over the leases.  

Permalink Reply by ABC on March 6, 2015 at 6:40am

We are about 1 mile north of Quaker City. Just got our lease money from Eclipse. Not sure if we will get drilled right away though. Thanks a lot you guys for all the info you post!!

Permalink Reply by bo boboski on March 13, 2015 at 10:44pm

Antero's new permitted well; The Turkey unit; off St.John's Rd. above Kennonsburg  has a couple laterals over 3 miles long. Is this the longest ever? They go Southeast under the lake ,past 147 and further .It'll take a while to drill these ones. They're spending one helluva a lot of $$$ on the access road to the pad and looks like they will be re-building St.John's rd. making it wider /better.

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