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Synergy Resources Corp (NYSEMKT:SYRG)

F2Q2014 Earnings Conference Call

April 04, 2014 12:00 PM ET

Executives

Ed Holloway - President and Co-CEO

William Scaff - Co-CEO

Monty Jennings - CFO

Craig Rasmuson - COO

Analyst

Mike Scialla - Stifel

Kim Pacanovsky - Imperial Capital

Ryan Oatman - SunTrust Robinson

Michael Kelly - Global Hunter

John Malone - Mizuho

Welles Fitzpatrick - Johnson Rice

Irene Haas - Wunderlich Securities

Joseph Reagor - Roth Capital Partners

Jeff Grampp - Northland Capital Markets

David Beard - Iberia

Richard Dearnley - Longport Partners

Operator

Good morning everyone and thank you for joining us to discuss Synergy Resources' Second Quarter Results for the period ended February 28, 2014.

With us today are Synergy Resources' Co-CEOs Ed Holloway and William Scaff Jr.; and CFO, Monty Jennings. COO, Craig Rasmuson will be available to answer questions during the question-and-answer session. Following the prepared remarks, we'll open the call to your questions.

Then before the conclusion of today's call, I'll provide the necessary precautions regarding forward-looking statements made by management during this call. I would like to remind everyone that today's audio conference call will be available for replay through April 11, 2014. The webcast replay will also be available via the company's web site at www.syrginfo.com.

I would now like to turn the call over to Co- CEO of Synergy Resources, Mr. Ed Holloway. Sir, please proceed.

Edward Holloway

Thank you Shae and thanks to everyone for joining us today. We issued a press release this morning, announcing our financial results for our fiscal 2014 second quarter ending February 28, 2014. The second quarter of the fiscal year represents another significant milestone for the company as we have reached 3917 BOEs per day during the quarter. This level of production is nearly double the rate we sustained during fiscal ’13 and demonstrates accelerated pace of growth from horizontal drilling. This level of production was achieved in spite of the significant challenges posed by severe weather, third party drilling contractor problems and continued mid-stream constraints experienced in the quarter.

This record production led to an increase in revenue to $23 million compared to $10.9 million in the year ago period. Our operating income grew to $9.5 million in the second quarter of ’14 versus $4.5 million for the second quarter of ‘13. During the quarter, our oil and gas production increased 90% over last year, to over 352,000 BOEs. We also achieved a 22% production growth in the second quarter over the first quarter even though the six horizontal wells we completed on Leffler pad did not come online until the lateral part of the quarter.

Encouraged by the early results and execution of our operated horizontal drilling program in January, we added a second rig to increase the pace of our leasehold development and growth. We are completing the six wells on our Phelps pad which will average over 25 stage fracs per well that will cost significantly less than our original budget of 4.5 million per well previously estimated for standard leak horizontal wells with a 16 stage frac.

This further demonstrates the increased efficiencies of our horizontal operations. I would like to point out that approximately half of our current production comes from horizontal wells and in the few short months that we have focused on developing horizontal wells we have equaled the production from the vertical wells drilled and acquired over five year period. Now our two rig program is setting the stage for a continued rapid production growth coming online in our fiscal fourth quarter ending August 31, 2014.

I would like now to turn over the call to CFO Monty Jennings to take us through the details of the financial results for the second quarter of our fiscal year. Thank you, Monty.

Monty Jennings

Thank you, Ed, and good day to everyone. Now, turning to our income statement; our revenues totaled $23 million in the second fiscal quarter of 2014. This represented an increase of 111% from the same quarter one year ago. The year-over-year improvement was due to the 90% increase in production.

The increase in production was enhanced by an 11% increase in our realized average selling price per barrel of oil equivalent. During fiscal Q2 of 2014, our average sales prices were $86.82 per barrel of oil and $5.93 per MCF of gas, as compared to $84.20 per barrel of oil, and $4.77 per MCF of gas for the year ago quarter.

Our operating income increased to $9.5 million, an increase of 111% from the second quarter of last year. Net income increased 89% from the year ago quarter, totaling $5.2 million or $0.07 per diluted share, versus $0.05 per share a year ago. Net income was reduced by an unrealized derivative loss from hedging activities of $1.8 million. Unrealized losses are a non-cash item. In this case the unrealized loss was equivalent to $0.02 per diluted share. Adjusted EBITDA, a non-GAAP term, increased to $17.5 million in the second quarter, which represents 76% of revenue, and is a 122% increase from the $7.9 million a year ago. Please refer to a more detailed discussion about our use of adjusted EBITDA, and its reconciliation to GAAP in the earnings release, which can be found in the news section of our website.

We were able to improve our margins even though certain cost increased during the period. Lease operating cost increased to $5.13 per barrel of oil equivalent from $4.19 per BOE, reflecting the impact of horizontal production, integration of acquired properties and increased environmental compliance costs. Especially during the early stages of production the operating cost for horizontal wells are greater than vertical wells. During the quarter, we integrated the newly acquired properties and incurred some integration costs. Notably, the disposal well has a slightly different cost profile than the other wells and it added about $0.50 per BOE to our average lease operating costs.

Finally, we are incurring additional compliance cost as we work diligently to meet the rigorous Colorado environmental standards. We also saw an increase in the DD&A rate, which increased $22.90 from $17.07 per BOE. The higher rate reflects the higher cost of horizontal development and the impact of our two acquisitions. The producing properties that we acquired have a higher cost per BOE than the wells that were developed internally. Although some cost increased, I would like to point out that we were able to reduce our G&A costs to $5.02 per BOE compared to $7.46. We continue to focus on maintaining overhead costs and being an efficient and low cost operator.

Briefly turning to the balance sheet. As of February 28th, we had cash and equivalents and short term investments totaling $54.4 million as compared to $79.5 million at the end of August our fiscal year end. We had $37 million outstanding on the credit facility with Community Banks of Colorado, the current interest rate on borrowings is 2.66%. We increased our commodity derivative activity during the quarter to mitigate short-term price fluctuations in the price of oil using swaps and collars we’ve had approximately 44,000 barrels per month of future production covering the remainder of 2014 and that is calendar year 2014. The average price of our swap position is approximately $95.17 per barrel for calendar 2014. During the quarter, our hedging position produced a realized loss of 191,000 and the aforementioned unrealized loss of 1.8 million, both of which were recorded in other income on the income statement.

I’d now like to turn the call over to Bill Scaff, our Co-CEO, who will provide more detail of our fiscal 2014 drilling program and the operational aspects of our business. Bill?

William Scaff

Thanks Monty. Our operator horizontal development in the Wattenberg Field is gaining momentum as we have planned. In the press release we issued last week we announced the addition of an automatic drilling rig to our drilling program as a replacement for the mechanical rig we used to drill our first 17 operated horizontal wells. With two ADR rigs, we now have more flexibility in maximizing our leasehold development going forward as we can now plan for mid and extended reach laterals on more than one drilling pad at a time.

We are in the midst of evaluating our leasehold and the underlying geology to assess how we can most efficiently drill wells from our pads in the future. While we remain diligent in controlling cost, we are also testing different completion techniques on wells on the same pad, striving to achieve optimum production with the quickest payback and the greatest EURs. To that end on our Phelps and Union pads, we will complete some of the wells using sliding sleeves and complete other wells using the plug and perf method. We are also going to compare side by side well results using slick water and hybrid gel fracs.

Additionally, we are refining the completions for the Codell which is a much thinner formation and the Limestone compared to the Niobrara which is seeker and a shale formation. Yet most operators are completing both formations with identical fracs. The wells we are drilling this fiscal year will provide different characteristics exhibited in the northern, southern, western and central portion of our leasehold in the Wattenberg Field.

With the aforementioned and theoretical data in hand, we will formulate our fiscal 2015 drilling program. We believe that it will be equally important to consider how many linear fee, number of frac stages and completion techniques are utilized versus the traditional focus on number of rigs and wellbores in a drilling program. In the northeast Wattenberg extension area, we have drilled the Buffalo Run well a test well in which we core to Greenhorn and side wall core in the Niobrara and Codell formations.

We also expended a nominal amount of additional capital to drill down to the D-Sand and evaluate its potential which was team not worthy of further expenditure. The Buffalo Run well was always intend my Synergy and our partner back to oil and gas to test its Greenhorn and Niobrara formations for horizontal development as its primary target. We hope to have the results backs in the lab within the next 60 days and will announce those findings at that time. The Buffalo Run well results as well as the results from the wells we are participating as a non-operated with Corrijo in the extension area, will factor directly into our fiscal 2015 capital expenditures budget for this area. In the meantime, we continue to manage the operational challenges presented when growing so rapidly. As we mentioned last week, we are approximately 30 days behind on completing the Phelps wells and bringing them into production.

Online pressures and midstream gas processing constraint continue to be an issue with our third horizontal pad coming on lined late in the third quarter we expect accelerating production during our fourth fiscal quarter. We are currently undergoing our midyear reserve report evaluation which will include a growing number of operated horizontal wells within that analysis. We will also announce our update reserves in the next few weeks and then work with our syndicated banks for an increase in our borrowing base in our credit facility. Our balance sheet remain strong with over 54 million in cash and short-term investments and only 37 million in debt, giving us ample liquidity to execute the remainder of our fiscal 2014 CapEx budget. We have reached another milestone expanding our footprint to over 50,000 net acres in the greater Wattenberg area and Northeast Wattenberg extension area, giving our shareholders significant exposure to one of most capital efficient oil and gas plays in the country today.

Thank you for your time and interest in Synergy, we will now open the call to any questions.

Question-and-Answer Session

Operator

Thank you. At this time we will be conducting a question-and-answer session. (Operator Instructions). Our first question comes from Mike Scialla from Stifel.

Mike Scialla - Stifel

Craig you mentioned the Phelps pad being behind, coming on late third quarter, just realized you haven’t given quarterly guidance but can you give sort of general direction, would that imply that third quarter production is going to be kind of flattish versus second quarter or are we looking at down a little bit or how do you think that’s going to look?

Ed Holloway

This is Ed, definitely we are looking at the third quarter not having the acceleration that we have had in the past quarters due to the timing of these pads. And what we are really, we have modeled in some slack time but when you lose all your slack on just the drilling portion going forward, this really pushed out our production growth and should really accelerate into the fourth quarter. We are still modeling out, trying to figure out how many of our non-ops will be coming on in the third quarter. We have quite a few non-ops coming in at that period of time as well and hopefully the Phelps pad will come on and contribute at least for 30 days of the third quarter. So, I would say we are not going to exhibit the growth, we just exhibited for this quarter.

Craig Rasmuson

We don’t give quarterly guidance. We come to work every day and try to create value and as we go forward, we just think that we are going to be a fourth quarter story in terms of the production coming online, fiscal fourth quarter.

Mike Scialla – Stifel

Okay, fair enough. In terms of, Monty talked about, you focused on keeping your overhead low, I am just wondering I think you have got staff of just about 25, 26 or so and I am wondering with two rigs running now, is that enough or where does that go over the next 12 month?

Ed Holloway

No, I think that’s enough at this point in time and I think we are fully staffed right now. We may add one or two more. It’s just a matter from the standpoint of two rigs and then as we put together our 2015 CapEx that’s where we will start looking at where we grow from there.

Mike Scialla – Stifel

Okay.

William Scaff Jr.

We also obviously with that staff we have a number of contract people, as we add range, we add completion or adding acquisitions obviously we are staffing up on the contract side. But as far as people being directly paid by Synergy or under Synergy’s umbrella, yes we are at 26, part of that is through our disposal where we find full-time people working at the disposal well also but it does not mean that we don’t have more people inline as far as geologists, engineers, people sitting on rigs, people putting their eyes on and if they just paid us contractors versus directly as Synergy employees.

Mike Scialla – Stifel

Okay, got it. And I think you mentioned your AFE is now lower with 25 stage fracs and where they were for 16 stage frac the 4.5 million they originally anticipated. I am wondering what is built into the budget? Is it something below that I assume 4.5 million per well and what are you assuming there in the budget for this year?

Ed Holloway

We’ll really find out on this Phelps pad is really what the cost of the plug and perf versus sliding sleeves. We know what the additional cost will be for adding additional fracs, we’re really trying to determine where that cut-off point of diminishing returns are at on the number of fracs per stage. When we budgeted 4.5 we basically came out with what was industry standard on their AFEs and we went in and plugged our numbers in and then everything else went into contingency and we knew we had a large contingency category going forward.

And so what we’re trying to do is just find out where that point of time and cost is the most efficient use of capital going forward. So we felt after our first 11 wells where we came in on those, that we could really add to the number of stages really test this and still stay way under the 4.5 number that we used in our preliminary budgets.

Craig Rasmuson

On the first two pads the Renfroe and the Leffler, we’re averaging right at $3.6 million per well. So additional frac stages will add some cost but we do expect to stay under the 4.5 million.

Mike Scialla – Stifel

So the Renfroe pad those were kind of 16 stage fracs and now given the cost savings…

Ed Holloway

Well on the Renfroe we had -- we’ve only had in our history one well operated with 16 stages, then we had…

William Scaff Jr.

We averaged 18 on Renfroe, we had one well at 20, 19, 18 and then obviously 17, 16. So that’s the average on Renfroe’s 18 stages, the average on Leffler was 20 stages and now we’re going to average close to the 25 stages on the Phelps as we complete those over the next couple of weeks.

Mike Scialla – Stifel

And just last one from me. But that 25 stages, is that -- how does that compare to by your competitors?

William Scaff Jr.

It’s pretty well in line with what others are doing, and as we stated before we’re not trying to reinvent the wheel here that this is we’re following kind of the trends we’re watching the bigger operators that are employing billions of dollars in the space. And we’re asking our service company also, what are they seeing the best results from what are the tweaks and motivations of things changing going forward and then what’s the cost to do that. Obviously, we had stages, but you get and it’s a 15%, 20% increase or 10% increase to your AFE, but that’s a 15%, 20%, 25%, 30% increase to your production it’s well worth the investment and that’s what’s we’re chasing.

Ed Holloway

It’s our next step before we go to mid-length laterals, stepping the process.

Operator

Thank you. Our next question comes from Kim Pacanovsky from Imperial Capital.

Kim Pacanovsky - Imperial Capital

Ed you said that the new rigs are capable of mid and extended reach laterals, I thought it was just mid or did I hear you incorrectly?

Ed Holloway

They are capable of mere than extended reach.

Kim Pacanovsky - Imperial Capital

They are, okay. So in Eberle, am I pronouncing that correct Eberle?

Ed Holloway

Yeah.

Kim Pacanovsky - Imperial Capital

Okay, you’re doing two mid-length collaterals on that pad. Is that again just a take it slow approach you’re not willing to jump to mid-length on all the wells on the pad? And is that just keeping with your thinking of looking at wells completed with maybe just one or two variables change, so you can apples-to-apples kind of make comparison?

Ed Holloway

Well on Eberle we definitely had the lease hold that allowed us to go to the mid reach lateral. And I will tell there are actually 7,100 feet and [indiscernible] describes their mid reach at 59 and anything over that is extended.

Kim Pacanovsky - Imperial Capital

Okay.

Ed Holloway

But we’re hoping to get 7,100 feet on those two. And two things have to take place, one is the geology has to lay correctly so that you can continually drill on tow up drilling length on these laterals. And then secondly as lease hold, and we’re trying to drill as many wells where we have a high working interest. And I think in Eberle we’re at right at 100% going forward there. So where on the previous pad Phelps we’re at 90% working interest. So we had the lease hold and we have the geology line up and rigs. So kind of had all three things going and we decided there notes – we might as well go ahead and extend out on this one and we’ve already got the drilling bid for that and the fracs and we think we can really be in there at a very competitive rate compared to other operators in the field.

Kim Pacanovsky - Imperial Capital

Okay, great. So then looking into fiscal ’15 then, how do you see the year kind of lining out with normal and regular length and mid-length laterals, just based upon those two factors that you just talked about, the geology and the lease hold?

Edward Holloway

Well, we’re definitely looking at all possibilities of what we can do because in ’15 what you’re going to really hear the Company come out and talk about is lateral feet drilled at number of stages of fracs. It’s not necessarily going to be number of wells drilled. And with this ADR rigs we really think we can drill about 50% more footage with just two rigs and that’s -- maybe accelerate to a third rig later in the year but coming out of the shoe we really, we’re hunting for the extended reach mid-lat and mid-laterals first and if geology and lease hold permits, that’s the direction we’re going to go.

Kim Pacanovsky - Imperial Capital

Okay, and then just another question on the production for 2014. I don’t want to beat a dead horse and I understand that when you have any kind of a delay -- on your basic production at this stage in your development, it makes a big dent sometimes and I get that. But we also want to have the right numbers. So for 2014, are you still comfortable with the guidance? Do you think you’ll be revising guidance for the year, and you’re like a 5100 number?

Edward Holloway

Let’s just put it this way. We weren’t comfortable in giving guidance to begin with. And we realize you guys live in a perfect world and we do not. One thing I can tell you is that when you lose days, it really hurts on the average basis. It will really depend on how these next couple of pads come on and how many pads come on in the fourth quarter, in the first part of the fourth quarter and not the last part of the fourth quarter. We really think our exit rate looks pretty strong, and so our average -- we just cannot at this point in time we would wish we could pull back our guidance in January.

It was a great guidance and we really felt that it was really achievable and we put in some slough time in there but we ate that all up basically on the drilling of the Phelps pad in 35 days behind time. And then you have delays and you have frac crews coming out, delays you some more, and then we also have the delay in the Leffler wells coming on. Those all are factors and your averages right? We don’t -- we will tell you this a hundred times. We don’t run our business quarter-to-quarter. We just run our business to create value on a daily basis. And God bless some of you guys, I hope we hit some of your guidance in our performance and exceed it.

Kim Pacanovsky - Imperial Capital

One quick other question. What percent of your production moves through Eaton and are there still upgrades that need to be done at that plant?

Edward Holloway

Go ahead.

Monty Jennings

It’s definitely over 50% of our production. When you look at the first 11 horizontal wells are all up in that neighborhood and then we have some of our better vertical pads where the Haythorn and the TK and the Leffler forward vertical directional wells that we had there. So when you look at the numbers just simply and that horizontals are contributing 50% of our production for all of our operated -- a lot of it is going through -- yes they are looking at re-routing some pipe up there. This Eaton is about 4 miles from the Lucerne plant that’s going to be coming on late this year with the expansion that DCP is doing. So I’m not sure if the Eaton plant being impacted or doing -- that the maintenance that they have done, and the upgrades they’ve done here recently, after the issue that was mechanical that shut them down. But the Lucerne plant will help that part of the basin greatly when it turns on.

Edward Holloway

I will say that that the Eaton plant isn’t of their better -- it’s probably the lowest ranking plant in the DCP setup going forward. So it’s fairly designed for a low GR verticals, and these horizontals are really challenging the plant.

Operator

Our next question comes from Ryan Oatman from SunTrust Robinson

Ryan Oatman - SunTrust Robinson

Well, I wanted to talk about this latest well pad, the Leffler. Given the fact that these wells had completion fluid marinate for almost a month on the mid-stream constraints, I’m curious about how the production profile looks. I know you guys have disclosed at a 30 day rate, lower than that, I’ve seen at Renfroe. How does the extended production on this pad compared with that seen at Renfroe?

Edward Holloway

I think what the real issue is with the Leffler is the Eaton plant and the ability for us -- we just had, give you a great example -- just last week the line pressure -- hit almost 400 pounds of line pressure and then drop down to a 160 and it is just all over the board going forward. The wells in their initial flow back looked very good for the short period of time before the plant went down. What we’re anticipating is that the decline curve on these wells are going to be shallower and that the IP or the production rates going to be lower. Going forward, we know we’re making a lot of oil and you have these fluctuations, fluids build up in the wellbore and basically drowned out the well and so that’s what the problem -- and I wish I had my field people here because they are working their rear ends off on that pad. It’s just been a workout going forward. But we’re encouraged about the liquid production going forward. I think the 30 day number we gave you is pure 30 days of calendar days, not production days but we’re still not getting consistent production days even today. We’re still trying to line those out, so they’re producing consistently on a daily basis.

Ryan Oatman - SunTrust Robinson

Right. And is it I mean kind of fair to say there is not as many conclusions to draw on the oil/gas split or do you feel like -- I know you guys mentioned that those do have higher than anticipated gas volumes on a percentage basis. Is that largely due to above ground or below ground you think?

Edward Holloway

I mean that’s a good question. I think it’s a good question, it’s probably below ground but as we continue to line those out, we get a much better feel as to exactly where we’re at there.

Ryan Oatman - SunTrust Robinson

Okay, okay. And how do those oil cuts compare to say the 68% that you’re seeing over at Renfroe?

Edward Holloway

We’re right at 65%. It’s not a major.

Ryan Oatman - SunTrust Robinson

Okay. Yes, I mean it seems pretty close there. Okay, so that’s understood.

Edward Holloway

Yes.

Ryan Oatman - SunTrust Robinson

And then moving onto that next pad the Phelps, have you all completed those wells yet?

Edward Holloway

We are in the completion stage as we speak and I will tell you we were supposed to start a week ago, Saturday and we had a delay of six days due to the operator that had the crew from Haliburton experience some problems on their pad and we were delayed about six days going forward but they are on location and fracking today.

Ryan Oatman - SunTrust Robinson

Okay. And you guys have talked earlier in the call about the decision to try the plug and perf, also slick water on those Phelps wells. Can you talk about a little bit more as to what you are trying to accomplish there and if you feel like whatever you find down there at Phelps, will that be applicable to the entire position or do you feel like that will only work on say the southern part?

Edward Holloway

I think it’s kind of a broad brush question. We have done a great job in-house here and through some of our contract engineers and geologists modeling what the other operators in that neighborhood done -- south have done and you have a share in higher geo-hour area. So the treatment does change a little bit but I think it does give us -- it gives us guidance going forward as we come back into the central part of the basin with their drilling program here later this year. So it’s just nice to be able to get a true look between plug and perf and sleeves with similar or the same for that matter treatments between hybrid gel fracs and the straight slick water frac, so we can see the differences in IPs but also 30 days, 60 days, 90 days.

So it’s going to be an ongoing evaluation of all the data that we’re going to get from these six wells and it’s also going to give us a little window of time, the Eberle is in the same unit. So, as we drill forward on the Eberle and schedule those for the completions around the first week of July hopefully, we will know better how we want to treat those wells and start honing in for the best methods there.

But we see the same thing. We are evaluating this. We’re getting ready to bring the drilling rig back to the central part of the Wattenberg here over the next few weeks. We are evaluating what the other operators in that neighborhood have done and their best treatment methods and they do tweak a little bit. So the rock is different from north to south and from west to east and your treatments tweak and that’s kind of us following the trends of the industry.

Ryan Oatman - SunTrust Robinson

Right, it makes sense. And then are there any kind of midstream issues for us to think about on the Phelps or Eberle pads or do you feel like those will be fingers crossed sort of cleaner production from those two pads?

Edward Holloway

I’ll tell you that a year ago when we were deciding our drilling program and the calendar if you will for drilling, obviously some of it’s motivated by lease terms and when your leases are expiring but one of the reasons we went down there obviously was to delineate the southern leasehold that we have but also DCP had encouraged us that they were at 160 pounds of pressure down there. The same week we move the rig in, late last fall DCP called me and said hey when you’re going to that pad and I said we’re there and they said oh we’re doing some maintenance and you’re going to experience high line pressure. So we’ve got compression there. We don’t think it’s extreme like it is up north. We’re not seeing the 300 plus but we are certainly seeing 220 to 280 on any given day down there and a lot of that is attributed to other horizontal activity. Anadarko is not far away with a lot of what they’re doing and Ken is doing a lot in that neighborhood. So it’s just the infrastructure getting stressed with all the horizontals coming in across the basin.

Monty Jennings

We are prepared with compression but we are hoping it’s going to be better in this area.

Operator

Thank you. Our next question comes from Michael Kelly from Global Hunter.

Michael Kelly - Global Hunter

Bill ,in your remarks you said that you’re currently in the midst of evaluating your acreage really in an effort to best understand how to optimize the asset and curious of the timing of that test or period that you’re looking at right now and what conclusions you’re ultimately hoping to draw? Is this something that you get comfortable with what you have here, you could layout and give visibility in this this ability to the street or maybe a two year drilling plan or what are you hoping to really decide based on the update?

William Scaff

Now that’s exactly what we’re hoping to really decide over the course of the next 30 days. We’re going to sit down with land -- with everyone. We’ve kind of got a preliminary look in as to how we’re going to proceed, whether it is to maximize each and every one of those pads, mid links, extended links, et cetera, et cetera. And over the course of the next 60 days we will be able to delineate exactly how we plan to proceed over the next two years, especially 2015 that starts September 1st.

Michael Kelly - Global Hunter

Excellent, great. And then how does the extension area in your eyes work into that plan and maybe you could talk about just offset industry activity there, maybe that’s given you any better insight into that acreage?

William Scaff

Basically from the standpoint of the test we just recently took. It’s going to be about another 60 days. We’ve looked at the logs extensively. We’re encouraged and till we get those core samples back, which again will probably be a full 60 days we’ll then sit down with -- who is kind of our G&G in that area and look at exactly how we proceed in that area as far as offset and looking at others.

Edward Holloway

Obviously [indiscernible] Noble have put a lot of emphasis and capital into just within 10 to 12 miles of where we’re drilling right now is the Red Tail and the East Pony and some of the other smaller operators in our neighborhood also there’s a group called Condor that’s directly west of us and we’re getting close for some of the other operators activities just less of us also but infrastructure is growing out there. We experienced -- just understanding that we’ve been very fortunate and our leasehold from our corporate office right here in Platteville is everything in the Wattenberg is an easy trip. Our people can leave the office within 30 minutes. We’re at any one of our locations within 10 minutes we’re at a lot of our locations.

And out there is a little longer run. When you’re holding water out there or you’re holding gravel it to build the roads it’s -- the infrastructure is growing, the gas lines are growing but there’s added expense at your evolution of development out there. So it’s something that when we get the logs back or we get the core samples back, hopefully it indicates to us and one of the things it will tell us is how to drill those wells north to south, east to west. Those are the type of things that we’ll relay and [indiscernible] experiences and also the site that sort of looking at the course for us.

William Scaff

And again as I had stated this is a Greenhorn area that we’re looking to move forward on. We’re well encouraged on what we saw initially. Once we get that back, Greenhorn is probably our primary target with Niobrara right there with it. So as we move forward we’re excited about this area looking towards the Greenhorn formation which no one else has done year-to-date.

Edward Holloway

And the other thing is we’re really watching Bonanza Creek in their Codell development. They’re talking about testing out some really thin beds in the Codell. So we’re watching that. For us the stage that we’re at, it’d be a real trap for us to go out and spend a lot of money out there and not have the takeaway capacity as Craig had mentioned.

So it’s going to be a keen focus in ’15 as to what percentage of our CapEx will go out there and we’re really -- like everyone has said -- we’re really anxious to see what the course bring back and then from that we can go back and look at Noble and everybody else’s logs on the Niobrara primarily and maybe even the Codell -- figure out what parameters our logs look like compared to offset operators going forward. And then as Bill said, we took on this whole project out of this area and it was basically Greenhorn play because the Greenhorn really thickens up through that area. And it’s productive in other parts of the basin. They’ve not really been explored to this point. So we’re really anxious to see how that comes out.

William Scaff

You’ll hear more about it later this summer and how that impacts our 2015 CapEx.

Operator

Thank you. Our next question comes from John Malone from Mizuho.

John Malone - Mizuho

Given that you still think that the guidance you’ve given in the past is potentially achievable, how much of that is a function of non-operating wells and the AFEs you’re getting? How much does that play into your production target?

Edward Holloway

Frank [ph], go ahead.

Monty Jennings

Right now we’re about 500 -- of the production that we’re currently about 500 barrels of oil equivalent a day is coming out of the non-ops. Going forward we still have a lot of AFEs coming in. They’re relatively small percentages. Right now we have in process 10 gross wells with non-operators. That equates to 0.75 net well. So they are there. It forms a nice base, but it doesn’t move the needle nearly as much as what we’re doing.

John Malone - Mizuho

Is it safe to say with Leffler that you guys are confident now that the issues was just a frac fluid resonance time and not anything to do with the rocks?

Edward Holloway

No I think we’ll have great data for you in six months as far as exactly what we have there. You get a lot of activity if you really were to map out and look on the website of where it is compared to -- PDCs got wells all over the north rim of us to the west of us, to the southwest of us and directly east of us.

So there’s just a lot of horizontal activity in there that they don’t fall into that model. Two of them fall well with it, the few others do not. But I think as quite enough gap lift, it’s getting lined out finally. We had a compression issue but the compression that we had initially had mechanical issues. So we changed our compressors. That’s given us encouragement here in the last few days, just here recent production. So we do think we’ve got the opportunity to have decent wells there. It’s just something that we’re really going to need four, five six months before we can give you full color.

William Scaff

And that’s because of the high line pressure John. When you’re bringing on wells and you are flowing them back and all of a sudden you shut them down right in the middle of flow back and then you bring them on 30 days later with high line pressure and you don’t have that big bump initially, that pressure come online, we just think that that’s what the impact is. We don’t think it’s a rock issue. It’s a matter of just lining them out a little bit more now overtime.

Edward Holloway

And we just make it practice not to flare. Also I just like to point that out. We’re just – it’s a highly populated area that as a company we have decided not to do any flaring within this area.

John Malone - Mizuho

And actually that leaves with my last question, which is anything you guys can say about the referendum, the frac band? Anything changing there on the grounds or new developments?

Edward Holloway

We’re concerned about it. I think they had to have -- whatever is going to get on the ballot had to actually be placed into the process as of yesterday. So we’re going to start hearing more and more about how they plan to try to proceed in that area. But everyday we’re looking at it, we’re talking to COGA, talking to Colorado, market was talking to the refinery. We met with Suncor. We’re going to continue to meet with Suncor about what the refinery is doing about it. So we’re very, very actively involved and again continue to be. And the question here is whether or not it’s really going to get on the ballot. We’ll know more as time goes on here. But again we’re not taking it lightly. We’re not ignoring it. That’s how things occur by just ignoring them. And so we’re very much involved and we’ll keep you updated as we know more.

Operator

Thank you. Our next question comes from Welles Fitzpatrick from Johnson Rice.

Welles Fitzpatrick - Johnson Rice

I know you’re not going to get the core back for 60 or 90 days. So this might be an un-fair question. But I think it was a little bit of a pleasant surprise that the Codell was there and from remembering Craig’s talk, you said that is about 60 foot or Greenhorn. So it’s shaping up like its thicker stack than I suppose I would have assumed. Is there any thought to doing a couple of vertical producers to try and hone in on the target, you’d want to go horizontal?

Craig Rasmuson

I think that was part of the discussion when we drilled to the The-Sand and the D show [ph] but it wasn’t necessarily commercial. And part of that issue was the gas line infrastructures two miles away is expending that capital to bring gas line down there for maybe 60 or 100 mcf a day on a well. We don’t want to – and the other thing is we don’t want to go ahead and contaminate that opportunity for all the horizontal laterals there. We don’t want to break that rock with anything but horizontals. So right now I think we just see -- we catch our breath and we’re going to crawl before we walk and before we run. And once we’ve devised a plan and have good results out there, we’ll be able to run off those good results.

William Scaff

Plus it lends itself well to horizontals. It’s actually 75 foot thick. We took samples, about 60 foot of it. So as Craig says, we don’t to contaminate with verticals. And if it looks like its perspective and has the capability of good storage within the reservoir then we’re going to take it horizontally. And that’s been our goal from day one.

Welles Fitzpatrick - Johnson Rice

And hoping a little bit further east, on the public data, it seems like there’s been a little bit of a ramp up in permitting over in Nebraska. Can you talk a little bit about what you guys might be seeing on the ground there?

William Scaff

What we’re seeing is strictly from and we spoke about this over a last couple of years is how we put that lease lot together. A lot of those leases are big blocks. They elected to take stock and not cash. And therefore we have a neighborhood watch going on out in this area and we’re kind of scratching our heads, because we’re little puzzled because George Seward our Director has gone out an eye witnessed nine rigs in the area, the coffee talk -- shop talk is that they are planning to bring in more rigs in this area going forward with one of the major -- and it’s going to probably triple their rig count going forward.

So we’re little puzzled by not seeing a particular permitting coming forward, but we are not surprised with the way things are going. But we know the activity is really pushing forward. We’re on top of it. There is a lot of seismic going on. So it started --like I said there is smoke there and we’re really keeping our eye on it because I think you’re going to see in ’15 that we’re going to -- part of our CapEx will be science -- primarily seismic going on in some of our lease blocks. And we may be -- our hand may be forced if an operator ends up encroaching close to one of our leases and hitting a discovery well. We would have to go out and start drilling in that area. So we’re keeping our eye on it very close. And then in our eastern Colorado acreage, what’s really interesting is reading a lot of companies permitting deeper test wells to the west and south of us. So we’re really watching that development as well.

Ed Holloway

Do you want to come out Wells? George will take you around and you can count them.

Welles Fitzpatrick - Johnson Rice

Any time. I’m still in Denver. Maybe we can do a quick slide today.

Ed Holloway

Well, it won’t be quick. It’s a lot of drive time.

William Scaff

Lot of windshield time and it’s in a very remote area.

Operator

Our next question comes from Irene Haas from Wunderlich Securities.

Irene Haas - Wunderlich Securities

I actually have three questions if you don’t mind. Let’s start with a simple one. Gas price realization looks pretty strong. Is it sustainable going forward because it’s probably some NGL pricing, and I don’t know how much runway you have to – kind of to do into that mix. Second question is reserves; when would we have an update? And thirdly, really going back to your Renfroe pad, that pad has been on for about six months or so. So just I want to know what the impact of gas lift and compression on this particular pad. Then additionally we kind of take a look at the Codell and it is actually performing much better than sort of industry average in the basin. Do you have any insight on it? Did you do anything terribly different on your two Codell wells at Renfroe? And that’s it.

Ed Holloway

Irene you asked if the gas price does include the NGL component were two stream report, so our liquids are buried in that gas price. You saw what happened to liquid prices during this quarter. That currently had a positive impact on us. And just like every other year, I expect gas prices to soften during the summer. Reserve update, we are in the process, right now with Ryder Scott. We expect them to finish up their work within the next couple of weeks. We’ll submit it to the bank. Their engineers will go through it. And so within 30 or 60 days we’ll have our new reserve numbers and an updated volume base.

Craig Rasmuson

This is Craig. In regards to the Renfroe and gas lift in the Codell. The gas lift, we added the gas lift in mid-January. So as you know those wells turned on in early September. So it really had the flush, if you will at the first 90 days off, and the gas lift added initially about 20% to our production for the first 30 days, once the gas lift is on. As of the last 30 days, it’s still at about 10% to 12% increase in production. So we are very encouraged with what the gas lift is doing for that Renfroe pad. As we talked earlier, that Renfroe pad is impacted also by some of the high line pressure. And we have the compressor for the gas lift, we have the compressor on the location to go ahead and fight our way in the DCP lines and keep those wells going. No magic recipe. I wish I could tell you it was something great that Ed or Bill decided to do and change on a frac or anything. It’s just, we’ve made two good wells there, two good fracs as far as the Codells, not as many stages that we’re doing going forward. So we’re encouraged that we can keep doing better in the Codell as going forward. But it’s just I guess good dumb luck.

Irene Haas - Wunderlich Securities

Maybe [indiscernible] had something to do of it.

Craig Rasmuson

I will tell you, we are a Codell focused company. Ed and I seeing in the basin since the early 80s. It’s always been the Codell-Niobrara. You've heard me say it before and we think there is a huge potential still remaining in the Codell that’s been untapped.

Ed Holloway

And Irene we also -- the Codell has always proved better producer over 30 years for us anyway. And I think the other think that people are really missing out on is that we know we have J Sand throughout our acreage and at some point in time when gas prices get to a certain level, we have that huge inventory of J sand underlying the majority of our acreage in the Greater Wattenberg.

Irene Haas - Wunderlich Securities

That’s right. And I guess you guys mentioned a little earlier that you’re going to try a different approach in terms of fracing the Codell versus Niobrara. Anybody else doing anything different. Like you mentioned it seems like everybody is applying the same formula for the two formations and they’re really compositionally different.

Ed Holloway

Well, what we are seeing Irene is that no one has a consensus as to what’s going on. So what we’re seeing is if an operator decides to move to slick water, they do slick water Codell, slick water Niobrara. No one is doing possibly slick water Codell and hybrid Niobrara and those are the things we’re looking at but it’s very evident from us watching all the completion imports going through the state that all the major operators are really also searching as to which is the most efficient way of going. The thing we are noticing is that they are adding more stages per lateral. That is the one consistent thing that we’re seeing throughout. We are seeing some operators switching over to plug and perf a little bit going forward. So we continue to monitor that through the state reports and through AFPs that we’re getting continually. How many AFPs do we have?

Monty Jennings

We have notices on about 90. We have AFPs on about 30.

Ed Holloway

Okay, we’re noticed on 90, AFPs on 30 and we are seeing some differences on these AFPs coming across on what they’re planning on doing.

Craig Rasmuson

But I will tell you Irene that we’re challenging the R&D department of Halliburton, Baker Hughes, Liberty. We’ve had numerous meeting, countless meeting, constantly trying to tweak what will we do different in the Codell versus the Niobrara.

Operator

Thank you. Our next question comes from Joseph Reagor from Roth Capital Partners.

Joseph Reagor - Roth Capital Partners

Just at this point only one or two questions; most of them have been answered. But just want to double check on timing on things. First of all it felt with the couple of day delay you’re still on pace for a May startup of production there?

Ed Holloway

That’s the full intent right now barring weather and/or mechanical issues as we’re pumping the jobs over the next couple of weeks with not having a crystal ball to know that everything is going to go as planned. It should have full intent to have production in May or early May.

Joseph Reagor - Roth Capital Partners

Okay. And then you would -- additionally the Union pad is still on schedule for a June start up as well?

Ed Holloway

That’s correct.

Joseph Reagor - Roth Capital Partners

Okay, then looking at the longer H laterals you guys are focusing on like the 7,100 feet, can you give us a little bit more color on what the cost saving were on a magnitude scale on the 4.5 million that allowed you guys to do that and what percentage of the cost savings are being reapplied to do those longer reach laterals and the 25 stage fracing?

Ed Holloway

Well, we’re going to have more stages in that longer lateral. We just have to wait to hear what it ends up being on an AFP basis but I think we’re really anticipating a very good number going forward and until we really do it and then have that number in hand, we really don’t want to disclose what we think that number could be.

Joseph Reagor - Roth Capital Partners

Okay, and then I missed your answer to this before. The prior guidance, is that still -- you guys still holding to that? Are you guys just excluding guidance completely going forward right now or is there some really [indiscernible]...

Ed Holloway

We’re basically saying that our guidance is been challenged and once we get another couple of pads on, we will definitely be able to fine tune that. Yet understand right now we are under a huge magnifying glass because it took us five years to develop the production of about 2,100 barrels a day average and within a short period of time we’ve been able to double that through horizontal drilling. But every little time delay, every little hiccup is a major event in this period of time for us. Once we have 30 to 40 wells under our belt and really get a good feel as to what we’re going, we’ll start giving a little bit better guidance going forward with a caveat that it’s in a range of about 50%.

Joseph Reagor - Roth Capital Partners

Okay.

Ed Holloway

I mean I’m just joking.

Craig Rasmuson

I think it’s safe to say we will either affirm or adjust guidance once we have Phelps pad on and we know the timing of Union and Eberle are there. So I think the timing for us to say something more on production guidance will be somewhere in the late May, early June timeframe.

Operator

Thank you. (Operator Instructions) Our next question comes from Jeff Grampp from Northland Capital Markets.

Jeff Grampp - Northland Capital Markets

Just curious on the plug and perf and maybe what you guys have seeing in Wattenberg. I know results have been a little mixed and I was curious if you guys have seen any pattern as to when it may or may not be more beneficial and maybe relating that to the Union and Phelps pads?

Craig Rasmuson

Just here in last six months have seen more of a trend as we’re meeting with our service companies. People used to only go to plug and perf if they had maybe a deviation in their lateral that they were worried about getting their sleeves put away and instead of going through that heartache and the expense of trying to get sleeves in and you can’t and then having to pull, they went straight to the plug and perf. That was the trend but I think through results obviously, because now you’ve got some of the bigger operators without naming them but the service company is working for us. Haliburton has named numerous companies to us who tell us, hey, they are now planning on plug and perf jobs. So that just indicates to us that they’re liking the results they saw. They are trying and stepping outside the box if you will on different trims and designs and technology.

So we’re obviously very optimistic that we are going to see the results. It’s added time and it’s a little added expense also and we will see how that moves our final numbers on our, final cost for the plug and perf versus the sleeves and that will help us. And once we have 90 days of production, it will help us decide and decide for whether or not it’s the routine for us going forward exclusively or if we keep a happy meeting between the two different routines or if we go exclusively to it, it’s going to be one of the three. The timing on plug and perf was factored into our guidance.

Jeff Grampp - Northland Capital Markets

Okay, got it. Thanks for that. And then moving over to Eberle, have you guys specifically decided on those mid-reach laterals, what the formation of that will be, BC or Codell nose?

Ed Holloway

We are drilling -- the first one is a straight C and we’re planning two Bs after that as far as the Niobrara, extended reach that will be, we’re planning just a straight B and that’s a thicker zone and we are confident we can keep that horizontal, lateral on the play we want to be in mid-length. One in the Codell and one in the Niobrara, yes I am sorry.

Jeff Grampp - Northland Capital Markets

Okay. So, one D bench, one Codell for the mid-reach?

Ed Holloway

That’s correct, sorry.

Jeff Grampp - Northland Capital Markets

Okay, got it. And then last one for me, can you guys comment on oil differentials and maybe what you guys have been seeing there lately? Has that been tightening up at all?

William Scaff

Yes, it’s tightened up quite a bit. I think we just had a glib in the market back in November and December. We have sold all of our crude for the last 30 years to Suncor or whoever onto, prior to Suncor and basically they call us one day and said hey look, we’re only going to be able to take so much -- actually we’re not going to cut you back here to 1000 barrels a day and so we’re not going to cut you back while we are cutting others back 30% because of our relationship whoa, whoa, whoa but we are going to be growing to 3,000, 4,000 very quickly and they said we have got to cut you back for now. So that made us go out and look at some other purchasers and when we did that, the range went anywhere from 750 that we were getting from Suncor through the end of last year because they kept us in that number all the way up to as high as what we heard is 22. And we were able to lock that in between 7.50 and 15.90. The worst that we have paid was the top range of 15.90.

Since then now those have all come down. They call came down effective February, lower in March and today our differential with Suncor is 1,050. We have three other purchasers that range anywhere from as low as 850 actually, just on one particular pad all the way up to around 11.10. So, that’s really tightened up to right around that $11 range and really when you look at that over the last couple of years, we have the benefit of that 7.50 for longer than expected. And so really going to an overall of around $10.50 to $11 is no way near as bad as it was back in November and December. We see that continuing to come down as more and more rail capacity and lines are going in and out of this area.

Ed Holloway

But the differentials in the second quarter did affect us by about 900,000 in revenue.

William Scaff

Yes, it was about $4 a barrel and we have historically been on the $7, $8 range and for this just ended quarter it was $11.50 a barrel.

Ed Holloway

And with this another crude pipeline going out sometime in August, we think it’s going to moderate. I don’t believe we’re going to see 7.50 in the near future but I think we possibly will get under $10 going forward once that comes about. So we’re seeing a softening and with our other purchasers now, we are going back to Suncor. We hope to be fully back to Suncor within the next six months, maybe one other purchaser to make sure we’re diversified.

Operator

Thank you. Our next question comes from David Beard from Iberia.

David Beard - Iberia

Two questions for you. First, given your gross number of wells that you identified I guess is 756, do you have a sense of how many might be candidates for the mid-reach to the extended-reach, just given that you have some block acreage, some smaller acreage. Can you give us some color there?

Ed Holloway

The color -- first we’re going to attack it from a geology standpoint to see what we really can and can’t do. And then once we identify that, we’ll look at our lease acreage there and we might have to bring in another non-op to fill out the extended reach side of the equation. Right now in the basin there’s a big trend after Noble and Anadarko blocked up all their acreage and they continue to block it up. And we’re in that conversation with all the operators on how we want to block up and go forward. And now we’re in conversations with some of the smaller operators that surround us and some of our acreage, how we can trade back and forth. So it’s just a continual ongoing process and trying to achieve those economic scales that looks like you can get from a mid-reach or extended reach lateral going forward. What was your second question?

David Beard - Iberia

I know we’ve kind of have a bunch of questions on guidance and stuff like that. But it seems to me if we gave you a couple three months, you’d feel a lot more comfortable about the number. In other words it seems to me really just a timing issue and nothing more. Is that fair or do you think there’s more nuance in there?

Ed Holloway

No thank you, that’s exactly right. If our year-end was December, we think we’d be hitting all numbers. I'm not saying we need three months more, but again it’s just all basically timing is what we’re talking.

David Beard - Iberia

That’s the rule of forecasting, give a forecast or a timeframe but not both. That’s how I interpret.

Ed Holloway

We’ll remember that.

Operator

Thank you. Our next question comes from Richard Dearnley from Longport Partners.

Richard Dearnley - Longport Partners

To what extent does the non-commercial D-Sand test show off that concept? How many of these do you have to do before you give up?

Ed Holloway

Well what really occurred there, the original exploration with Synergy and Vector [ph] was just to drill down to the Greenhorn and core the Greenhorn. Actually we did some additional side wall cores because the Greenhorn was so thick that we did additional side wall cores in the Greenhorn. And we took side wall cores in the Codell which I believe was 3 feet to 5 feet thick. And then we also did the Niobrara side wall cores. But in our analysis this area has a channel play in the D and we said well for a nominal amount of capital to drill another 150 feet, we’re there on location, let’s go ahead and take it down to the D.

We really misrepresented it when we basically said it was a D -- it was a D test but it wasn’t originally designed for a D test but when you’re on location and you’re able to just spend a very small amount of money to go ahead and test to see if we hit the D, it just wasn’t commercial. And we’re not chasing the D out there, through of any other times we’re drilling and there is additional deep zones that need to be looked out, we’ll take them, because the initial cost is just getting the rig there and drilling the first 6,000 feet.

So we weren’t really counting on it, we were -- let’s just say keeping our fingers crossed it would have been nice to have hit that, but it’s not there and we are the operator that lease walk and we have 35% working interest in that whole lease walk, just to let you know that as well.

Bill Scaff

Our partner, Vector Oil & Gas was chasing D there a little bit more further to the south and to the east and they just said look, while we run this test, could we go ahead and go down to the D? We said absolutely. They weren’t really optimistic but they said, like Ed said, for the additional cost let’s go down to the D. Once again, this is a Greenhorn test area, 75 foot horizontal Greenhorn. That’s our primary target.

Richard Dearnley - Longport Partners

Had that could have been hitting the D-Sand, the south and west?

Ed Holloway

That was their original – when they were putting this lease block together, that is really what their group was looking for along with the Greenhorn. The Niobrara play came over the top of them after they had already put their lease block together. So it had a lot of data on the D and we thought we had a legitimate shot at hitting it. But like I said it’s a channel play which is very allusive, very productive when prolific, when you hit it but very allusive. And so we went. And as you remember Dick that in our vertical development where we had good shots on the J-Sand for the incremental small cost that we took, we went down and took the J, and the same philosophy here.

Richard Dearnley - Longport Partners

Okay. And then where was the acreage added that was in the release of two days ago for the stock distribution for the acreage. Where were those new leases?

Ed Holloway

Primarily those leases were in Eastern Colorado and mainly in Nebraska where we’re -- we had made a commitment a couple of years ago with those leases that we came due that we'd lease it. Or it was helping us block and tackle outward. We're blocking up in that area, we're really not taking on any other bigger blocks but some leases are next to us and blocking it up or taking those leases in the anticipation of shooting seismic going forward. So we're probably -- we're really at the tail end of that position until we start developing out there.

Richard Dearnley - Longport Partners

So it was Yuma County and Nebraska?

Ed Holloway

Exactly. 90% of it was Nebraska.

Operator

Thank you. At this time we have no further questions. I will turn the call back over to Mr. Holloway for closing comments.

Ed Holloway

Thank you, Shane. This is an exciting time in Synergy's operating history as the increase in production from horizontal drilling begins to impact our revenues, cash flows and reserves. We are focused on the Wattenberg Field to provide growth for our Company as we deploy the latest best practices proven in the field combined with a keen focus on controlling costs. Thanks everyone for joining us today and for your interest in Synergy Resources. Please don’t hesitate to contact us if you have any further questions. Operator you can now conclude the conference call and I'll turn it back over to you.

Operator

Thank you. Before we conclude today's presentation, I would like to take a moment to provide important cautions regarding forward-looking statements made during this call within the meaning of the Private Securities Litigation Reform Act of 1995. These statements are subject to risks and uncertainties and are based on the beliefs and assumptions of management and information currently available to management. The use of words such as believes, expects, anticipates, intends, plans, estimates, should, likely or similar expressions indicate a forward-looking statement.

The identification in this presentation of factors that may affect the Company's future performance and the accuracy of forward-looking statements is meant to be illustrative and by no means exhaustive. All forward-looking statements should be evaluated with the understanding of these inherent uncertainties.

Factors that could cause our actual results to differ materially from those expressed or implied by forward-looking statements include, but are not limited to, the success of the Company's exploration and development efforts, the price of oil and gas, the worldwide economic situation, any change in interest rates or inflation, the willingness and ability of third parties to honor their contractual commitments; the Company's ability to raise additional capital, as it may be affected by current conditions in the stock market; and competition in the oil and gas industry for risk capital. The Company's capital costs, which may be affected by delays or cost overrun; the Company's cost of production; environmental or other regulations, as the same presently exist or may later be amended; the ability to identify, finance and integrate any future acquisitions and the volatility of the Company's stock price.

I would like to remind everyone that today's presentation will be available for replay through April 11, 2014 starting in approximately two hours. Please refer to this morning's press release for dialing instructions. A replay of the audio webcast will also be available via the company's Investor Relations section at www.syrginfo.com. That’s www.SYRGINFO.com.

This ends our presentation. Thank you for joining us today. You may now disconnect.

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