Synergy Resources' CEO Discusses Q2 2013 Results - Earnings Call Transcript

Apr. 9.13 | About: Synergy Resources (SYRG)

Synergy Resources Corporation (NYSEMKT:SYRG)

Q2 2013 Earnings Conference Call

April 9, 2013 12:00 PM ET

Executives

Edward Holloway - President and CEO

Monty Jennings - CFO

William E. Scaff Jr. - EVP, Secretary and Treasurer

Craig Rasmuson - VP, Operations and Production

Analysts

Irene Haas - Wunderlich Securities

Welles Fitzpatrick - Johnson Rice & Company, LLC

Stephen Berman - Canaccord Genuity

Jared Lewis - Northland Securities

Kim Pacanovsky - MLV & Company

Joel Musante - Euro Pacific Capital

Jack Aydin – KeyBank Markets

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, 2013.

With us today are Synergy Resources’ President and CEO, Ed Holloway; the Company’s Executive Vice President, William Scaff, Jr.; and CFO, Monty Jennings; Vice President of Operations, Craig Rasmuson will be available to answer questions during the Q&A 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’d like to remind everyone that today’s audio conference call will be available for replay through May 9, 2013. The webcast replay will also be available via the Company's website at www.syrginfo.com.

I’d now like to turn the call over to the President and CEO of Synergy Resources, Mr. Ed Holloway. Sir, please proceed.

Edward Holloway

Thank you, Ruya, and good afternoon everyone. Thank you for joining us today. We issued the press release this morning announcing our financial results for our fiscal second quarter, which ended February 28th. We’ve also filed a 10-Q today, which will be available via our investor relations section of our website.

As we reported in the release earlier this morning, we continue to execute on our vertical drilling program in the Wattenberg Field, which drove strong production growth and record revenue this quarter. We achieved a 76% increase in revenue over the year-ago quarter, totaling a record $10.921 million. This drove our operating income up more than 56% to $4.5 million and generated net income of $2.7 million or $0.05 per share.

During the quarter, our oil and natural gas production increased 87% over the same year a year-ago to a total of $186,039 BOEs for the quarter, this equates an average of 2,067 BOEs per day during the quarter versus a daily average of 1,091 BOEs per day a year-ago and an increase of 90%.We also achieved sequential production growth with average daily production increasing 25% versus last quarter.

We continue to drill rapidly in the pace of persistent takeaway issues as our midstream partners upgrade the existing gathering and processing systems. We believe these midstream issues will continue into the foreseeable future as the pace of activity of horizontal drilling by other operators has accelerated across the Wattenberg Field. In late February we brought online the final 16 vertical wells that were drilled earlier this fiscal year. This increased the total number of wells we’ve drilled as operators since inception to 134. All of these wells are now in production. As of the end of the second quarter, we had completed, acquired, participated in a total of 280 for oil and gas wells including six wells that were in progress. We are working with our reserve engineer Ryder Scott to update our PV-10 reserve report.

I’d like to now turn the call over to our CFO, Monty Jennings, to take us through the details of our financial results for the quarter. After Monty’s remarks, Bill Scaff will discuss additional highlights in the quarter and then finally we will open up the calls to your questions. Monty?

Monty Jennings

Thank you, Ed and good day to everyone. Now turning to our income statement, as Ed mentioned, our revenues totaled to $10.9 million in the second fiscal quarter of 2013. This represented a sequential increase of 31% from the previous quarter and up 76% from the same quarter a year-ago. The year-over-year improvement was due to the 87% increase in production. This increase was primarily attributed to the new wells that have come online and the acquisition of the Orr wells, which was partially offset by a slight decrease in our realized average selling price per BOE.

During fiscal Q2, 2013, our average sales price was $84.20 per barrel of oil and $4.77 per Mcf of gas as compared to $92.33 and $4.09 for the year-ago quarter. Our operating income increased 26% from the previous quarter to $4.5 million and increased 56% from the first quarter of last year.

Net income increased 22% from the previous quarter totaling $2.73 million or $0.05 per basic and diluted share. Net income was down 55% from the first quarter a year ago. It’s important to note that net income in the second quarter of 2013 was burdened with income tax expense at an effective rate of 37%. One year ago the second quarter included a one-time tax benefit of $3.2 million to recognize the value of our net operating loss carry forward. This difference between tax expense of $1.6 million compared to a tax benefit of $3.2 million is $4.8 million, which equates to nearly $0.09 per average share outstanding. If you exclude the impact of deferred tax items and look at pre-tax income, the 2013 quarter increased to $4.3 million almost $0.08 per share, an increase of 50% from the 2012 quarter of $2.9 million or $0.06 per share.

Speaking of deferred tax items, we do not expect to make significant income tax payments during the current year as the reported tax expense represents a 37% tax on book income and for tax purposes substantially all of our tax payments will be deferred in the future periods.

Adjusted EBITDA, a non-GAAP term, increased 30% from the previous quarter to $7.9 million, which represents 72% of revenue and as an increase of $3.3 million compared to one year ago. Please refer to our 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.

Now briefly turning to the balance sheet. We continue to deploy capital in a measured and consistent manner with a focus on driving a strong production growth profile. As of February 28, 2013, we had cash and equivalents in the bank of $18.3 million as compared to $19.3 million at August 31, 2012.

During the quarter, we drew down $38.5 million from our credit facility with the Community Banks of Colorado. A significant portion of the borrowed funds was used to fund the Orr acquisition. As of February 28, 2013 we had borrowed $41.5 million out of a total of $47 million borrowing base. The line of credit is asset based and subject to semi-annual reviews by the participating banks as Ryder Scott updates our reserve report and PV-10 valuations.

As we increase our proved reserves, we will be able to access additional amounts under the line of credit to fund our drilling program, future acquisitions and leasehold expansion. The current interest rate on borrowings is LIBOR plus 3%. We commenced a commodity derivative program during the quarter to mitigate short-term price fluctuations in the price of oil. Using swaps and collars we’ve had 188,000 barrels of future production covering the remainder of calendar year 2013 and all of calendar year 2014. The average price of our swap position is approximately $94 per barrel for 2013 and $90 per barrel in 2014.

During the quarter, our hedging position produced realized losses of $20,000 for January and February settlements and unrealized losses of $134,000 both of which were recorded in other income and in the income statement.

In summary, between our cash generated from operations and access to the enhanced credit facility, we remain well positioned to fund the remaining portion of 2013 CapEx program.

Now I’d like to turn the call over to Bill Scaff, our Executive Vice President, who will provide more insight into the operational aspects of our business. Bill.

William E. Scaff Jr.

Thanks, Monty. The first half of our fiscal 2013 year has been very rewarding as the solid asset base of our vertical wells continues to generate positive results quarter-over-quarter. During our fiscal second quarter we completed the remaining wells we drilled and operated during the first quarter, including 16 wells that we brought online during the final 10 days of this quarter. These wells are now contributing to our production, which exited the quarter at approximate rate of 2,500 BOEs per day, which does include our non-operated production.

In regards to horizontal wells, today we’ve participated in 10 horizontal wells as a non-operator in the Wattenberg. The performance of our non-operated horizontal wells has been consistent with industry result in the field. These 10 wells are comprised of five Niobrara B, and four Codell and one Niobrara C bench completions. In our Northern DJ Basin acreage, we’re participating as non-operator in one well of 4,500 foot length Niobrara B Bench.

Speaking of the Northern DJ Basin, on March 13, 2013 we announced the closing of an agreement with Vecta Oil & Gas whereby we substantially increased our exposure in an area which is increasing drilling activity by other oil and gas companies. The Vecta deal fits us carry on several funds. First, they expanded on net acreage in the area by nearly 40% while spreading our risk across the larger section of the play. Secondly, it allowed us to do it at competitive prices. As our average cost breaker of more than 19,000 acres in the Northern DJ Basin is now – is approximately $400 per acre with an average of three years left on our leases and options to extend the leases in other two or three years at less than a $100 an acre.

The agreement also provides Synergy with retaining operational control while gaining the insight and collaboration with Vecta who has considerable technical [acumen] in geology and geophysics. Lastly, the area of potential for multiple pay formations including the Greenhorn, Niobrara, D-Sand and J-Sand. We are planning to drill – we are planning on drilling a test hole in this acreage during our first quarter in fiscal 2014.

Other activity in the quarter included a successful closing and integration of Orr Energy. The Orr assets are already proved valuable to Synergy as an addition to the current production they’re providing. We have received many notifications from other operators with the intentions to drill horizontal wells on this acreage. We intend to participate in all of these potential wells.

In addition to the non-operated horizontal wells that we’ve participated which I described earlier, we have also received another 30 plus notifications for horizontal well to cross our acreage position in the DJ Basin. We’ve continued to execute on our plan, $82 million CapEx budget in fiscal 2013, having completed the vertical well portion of the program, closing the Vecta deal and the purchase of other undeveloped acreage, we’ve met the $5 million budget for leases in acquisitions and we’re well in to our budgeted non-operated vertical and horizontal well program.

During our first – during our final two quarters this fiscal year, our third and fourth quarters, we will finish our CapEx budget with during half rated horizontal wells and vertical well completion. We are currently finalizing the permitting and site preparation of potential path size and plan on starting the first of our operational horizontal wells in mid May. Our first horizontal wells are most likely be comprised of both Niobrara and Codell wells drilled from one or two paths. We will provide more details when appropriate.

We also have plans to drill our first well on our acreage in Yuma County, in Eastern Colorado. The well will be a conventional Niobrara well and this proven gas field that will cost an estimated 175,000 to 225,000 to drill and complete. With gas prices near $4 per Mcf, wells in this area could provide strong economic returns. Synergy will have a 45% working interest in the well with [Augusta] Energy based out of (indiscernible) Montana who is the operator and owns the remaining working interest.

Currently we have engaged our third-party reserve engineer Ryder Scott to evaluate reserves as of the end of February and we plan to utilize this valuation to increase our borrowing based on our current $150 million credit facility provided to Community Banks of Colorado and the syndicate that they’ve assembled. At that time we will then determine our fiscal 2014 capital budget and convey that information to the public.

Lastly, I’d like to mention that we’ve recently added three key employees to our team, Terry Dewey as Production Manager; Jon Kruljac as VP of Capital Markets & Investor Relations; and Ron Morgenstern as VP of Land & Business Development. These additions strength our ability to continue our rapid growth. We remained dedicated to enhancing value to our shareholders. Thank you for time and interest in Synergy and now we will open the call to any questions.

Question-and-Answer Session

Operator

Thank you. We will now be conducting a question-and-answer session. (Operator Instructions) Thank you. Our first question comes from the line of Irene Haas with Wunderlich Securities. Please proceed with your question.

Irene Haas - Wunderlich Securities

Hey, good morning everybody. I have a question on the Northern well that you’ve drilled, you said that you drill in Niobrara B well, just wondering if we can have some color on that and how close is that well to your Vecta JV then?

Edward Holloway

This is Ed, Irene. The well we participated with Noble on in their East Pony and its just North of our Vecta acreage, we’re still waiting on production results that came online, I think late November, maybe early December and we still haven’t – we had all the production results yet. It is – the two months that we have that keeps increasing so, we just haven’t got any clarity from Noble at this point on that well.

Irene Haas - Wunderlich Securities

But you’re earning, I mean, you’re getting a production and you’re selling the oil I assume from this well?

Edward Holloway

Correct. I think sales started what December …

William E. Scaff Jr.

First week of December.

Edward Holloway

First week of December. We just for whatever reason Noble hasn’t given us production for January and February and March.

Irene Haas - Wunderlich Securities

And when will that data be sort of public, be filed with the state, do you know?

Edward Holloway

I think it’s already public with the state. If it is not, I will ask Craig, because he is the one who pulled that production.

Irene Haas - Wunderlich Securities

And do you have the name for the well?

Edward Holloway

The Castor.

Irene Haas - Wunderlich Securities

Okay.

Edward Holloway

CASTOR.

Irene Haas - Wunderlich Securities

Great. Thank you.

Monty Jennings

(Indiscernible) just started getting production information on that with Noble.

Edward Holloway

No, no it was through Noble.

William E. Scaff Jr.

Yeah. That was on in the first two months.

Edward Holloway

It was only – yeah, it was just limited information. We will know more here in the next month or two.

Irene Haas - Wunderlich Securities

Great. Thanks.

Operator

Thank you. Our next question comes from line of Welles Fitzpatrick with Johnson Rice. Please proceed with your question.

Welles Fitzpatrick - Johnson Rice & Company, LLC

Good morning. You guys obviously talked about how you’re still somewhat in between the two paths with two wells (indiscernible) so one with four, but could you talk a little bit about what you’re thinking as far as horizontal spacing?

Edward Holloway

Well, we’re currently – we’re probably going to go with 80 acre spacing on those at this point of time. I know the trend right now is 40, but I think we’re going to take a more cautious approach at this point in time and go with 80 knowing that we can come back at a later date and infill that and also be able to book the offsets to those horizontals as we go forward.

Welles Fitzpatrick - Johnson Rice & Company, LLC

Okay. And when you say that Niobrara will probably be the target for the lease period that is -- I assume it’s safe to say that Niobrara B, right?

Edward Holloway

Correct.

William E. Scaff Jr.

Correct.

Welles Fitzpatrick - Johnson Rice & Company, LLC

And is it also safe to assume that, that 1Q ’14 as you talked about on the Northern acreage that will be a horizontal?

Edward Holloway

First of all, are you talking about the Vecta acreage?

Welles Fitzpatrick - Johnson Rice & Company, LLC

Yes.

Edward Holloway

First of all, that should be a vertical test well. We take core samples and then decide how to proceed from that point, but the goal is that with horizontal Greenhorn.

Welles Fitzpatrick - Johnson Rice & Company, LLC

Okay. Perfect. And can you remind me if you have 3D over the Northern acreage?

William E. Scaff Jr.

First (indiscernible) had the 3D.

Edward Holloway

Over some of it and we will 3D before we start our well.

Welles Fitzpatrick - Johnson Rice & Company, LLC

Okay. Perfect. Thanks so much. That’s all I have.

Edward Holloway

Thanks, Welles.

Operator

Thank you. Our next question comes from line of Steve Berman with Canaccord Genuity. Please proceed with your question.

Stephen Berman - Canaccord Genuity

Good afternoon. Couple of questions. Ed, one clarification the 30 notifications you’ve gotten for future horizontals are those actual AFEs and is that over and above the 10 you’ve already got on production, I just want to be clear on that, those numbers.

Craig Rasmuson

So those are recent – this is Craig Rasmuson, so those are recent notifications from various operators throughout the Basin. Most of them are in the Wattenberg, a few of them are in the Northeast extension and we do have AFEs on the majority of those, we’ve a target spud date some form fiscal year ’13, a lot of them roll over to fiscal – first part of fiscal year ’14.

Stephen Berman - Canaccord Genuity

All right. And in terms of keeping your CapEx budget to the same number, you’ve been talking about would you maybe try and push some of those into the next fiscal year to keep your budget where it is, just these numbers are so much higher than where they’ve been, I’m just trying to see how you keep your CapEx with that (indiscernible)?

Craig Rasmuson

Well, it’s always a juggling act and with our end of year being August 31st, those are variable there and where they’re going to fall and we’re very proactive in giving in front of them to find out exactly what quarter they’re going to fall in and try to at least get it in within a 90 day window. At this point in time I think we’re fine. But it is a weakly event on how many horizontals that we have going forward, and I think what this really tells everybody is the high quality of our acreage position that with us controlling 65% of our horizontals about a 100% the other 35% is more op to be non-op and that’s generally the part you can’t plan on and it's all being drilled up as we speak, I mean on a continual basis. So, a lot of it is following in that we’re being notified is following into our ’14 and their ‘14. They will tell us first quarter of ’14 so at least we’re getting notified way out in advance of major pad drilling, I mean two pads have eight wells and several well would have six. So we’re getting -- they’re notifying us and giving us quite a bit of notice ahead of time.

William E. Scaff Jr.

Yeah. And Steve these first 10 wells as I talked about we average about 20% participation, so on a recurring CapEx and depending how they fall we should be okay 2013, and that’s why we are currently putting together our 2014 budgeted CapEx.

Stephen Berman - Canaccord Genuity

Got it. And then one more, can you elaborate a little bit on the infrastructure issues and what synergy can do is just being proactive as far as that issue goes?

Craig Rasmuson

This is Craig again. We are constantly working with adding compression to our multi-well pads. We’re in the process of adding compression to the few of the Orr pads from our acquisition in December. It's really, we’re kind of -- it's a moving target also, it's if someone brings a pad of horizontal wells on in the neighborhood of one of our existing pads that maybe has been managing and still producing against the high line pressure, then that pad will get shut in for a time period while the volume comes out those horizontal wells. So we’re chasing and adding compression as we know things are coming on in the basin. That’s just an everyday event of trying to manage to make sure we maximize and have every one of our wells producing against this high line pressure.

Edward Holloway

And I do want to make at this point in time what a great job our field people did in this last quarter of keeping up with all this, but we did experience line freezers for the first time in couple of years where when you’re bringing on this many wells of production equipment cannot separate properly so you get a lot of water into your gas cells lined and with the frost being driven down to three to four feet is that we’ve had freeze ups in the lines and it takes DCP or Anadarko quite a long time to fog those out using methanol and for this last quarter we had potential days of production. We were down 15% of those days and generally you’re looking at being at a efficiency rate of 97% of total days produced in a quarter you’d like to see it and we’re at 85%. So it did affect our capability to produce even where we did have compression.

Monty Jennings

The good news is we exited the quarter at 2,500 BOEs per day because the field people did do such a great job of making sure we had compression on every one of the wells or the pads where we needed it. We got those freeze up start out and move strong into March. The freeze ups are a short-term, it's really a February, well sort of in January because we had such a mild winter this winter and then a tougher winter late when spring started but the high line pressure will continue with the persistence of the horizontal drilling going on. We are in the home stretch though DCP is opening up that 110 million cubic feet of gas plant in LaSalle, they’re shooting for a July, August opening right now. So we’re feeling about the time we turn on our horizontals hopefully the high line pressure will have a good [band aid] on it it's not going to have us some side down below 200 pounds again with all those activity, but it will be out of the 280s hopefully back down to something more manageable with our horizontal production.

Stephen Berman - Canaccord Genuity

Great. I actually did think of one more thing, anything on new happening around you in Nebraska if you can share with us?

Monty Jennings

Well, really what is – there was nothing from Apache that we’re aware of and that [ph] Four Star out at Dallas did make a announcement in January of hitting a 218 barrel a day vertical well in the Lansing Pennsylvanian Lansing Group and it had I think 125 barrel a day 30 day average. We are aware of several other vertical wells that have come on in that range, but no one has made the announcement. So we are watching – right now we’re just watching the vertical players going and unfortunately we don’t have a lot of public entities out there, they’re all private – majority of them are private, so none of the announcements are being made. But the seismic activity and the vertical activity has been picking up.

Stephen Berman - Canaccord Genuity

All right, terrific. Thank you, gentlemen.

Monty Jennings

Thank you, Steve.

Operator

Thank you. Our next question comes from the line of Jared Lewis with Northland Securities. Please proceed with your question.

Jared Lewis - Northland Securities

Good morning, guys.

William E. Scaff Jr.

Hi, Jared.

Edward Holloway

Good morning.

Jared Lewis - Northland Securities

Couple of quick questions, one just on the Ryder Scott report; do you have like a timeline when you think you might have that information released?

Edward Holloway

Well, we’re scheduled to do our final review with Ryder Scott the end of this month and then we’ll be able to make that public either right at the end of this month or early in May.

Jared Lewis - Northland Securities

Okay, excellent. And in LOE expense and the DD&A increased a bit sequentially, what are you kind of attributing that to and where do you see that going forward?

William E. Scaff Jr.

Yeah there are two different answers there, on the LOE expense we are picking up some extra costs with the compressors that we’re adding to the pads. We’ve also done some work on the Orr wells to kind of improve the flows there. With regard to the change in the DD&A rate that does reflect the inclusion of the Orr assets into the amortization base and it pumped it up to about $17 per BOE.

Jared Lewis - Northland Securities

Got it. And just real quick finally on your first horizontal, you expect to spud mid May, I believe you said. What kind of timeline are you expecting to get that drilled, completed, have you decided on what the design is going to look like just a little more color on that?

Edward Holloway

Well we’re working on the design -- we have been working on the design. It's pretty well laid out. The real question is; are we going to drill four on one pad or are we going to do two on one pad and two on another. If we do four on one pad it delays it out another 20 to 25 days before we have them into production. If we do two and two that will shorten that up and maybe some of that production will hit in the fourth quarter. We are just not certain how that time, which way we’re going to go yet. We’re still debating that.

Jared Lewis - Northland Securities

Okay, excellent. I’ll jump back in the queue. Thanks.

Operator

Thank you. Our next question comes from the line of Kim Pacanovsky with MLV & Company. Please proceed with your question.

Kim Pacanovsky - MLV & Company

Hi, good afternoon everyone. I was just wondering what your planned lateral length is on your first well?

William E. Scaff Jr.

We’re approximately 4900 feet. Kim, we owned the full leasehold of 320 we’re drilling also on own the contiguous leasehold to the north of that, so we’re going to take it to the section line. So it will be just a bit longer than the traditional 320 spacing.

Kim Pacanovsky - MLV & Company

Okay. And, what was it, I can’t remember was it this week or last week. It was this week, last week, sorry at the PDC Analyst Day in New York, they had mentioned that even for their size of market half they were not comfortable with the extended reach laterals because of the additional risk in drilling those longer laterals. And I’m wondering when you have AFEs come in, if you have a high working interest in a well that is an extended reach lateral, how do you look at that and how do you look at your risk profile, I know that you’re not going out and drilling those wells, but how do you look at the risk profiles of the wells you’re AFE on?

Edward Holloway

Well to date the vast majority of the shorter laterals, they actually come in three sizes. One is under 5000 foot, the other one is what we call a mid lateral at 6500 feet and then to maybe 7000 and then the longer lateral be at now 9000 foot laterals. We are watching that very carefully with each operator and definitely if we were -- if we had a proposal to drill long lateral with an operator who hasn’t done that we would probably market that.

Kim Pacanovsky - MLV & Company

Okay.

Edward Holloway

But if it's a Noble, Anadarko maybe even in Canada we would have a more of a tendency to go with it because of their experience in doing those. But we are not seen any especially the long laterals. I think we [Creso] has AFE this out in the extended area, but a long lateral but we only have roughly 3% in that give us great diligence and info on that well at a very low cost, and we are participating on that one, but we have not been AFE on any long laterals and I think only a hand full of the mid laterals at this point in time.

Kim Pacanovsky - MLV & Company

Okay. And then this 30 AFEs that you spoke about earlier what is your total capital requirement for those 30?

William E. Scaff Jr.

We don’t have that data yet, Kim.

Kim Pacanovsky - MLV & Company

Okay.

William E. Scaff Jr.

We’ll be getting that in over the course of the next two to three months.

Edward Holloway

Once we define what year they fall in because we got to break that out.

Kim Pacanovsky - MLV & Company

Okay.

Edward Holloway

That’s why we’re surveying each operator at this point in time.

Craig Rasmuson

(Indiscernible).

Craig Rasmuson

Yeah, so the remaining that we talked about, I told you [the first 10 averaged] 20%. The remaining of the wells are actually averaged less than that.

Kim Pacanovsky - MLV & Company

Okay. And then, I guess I’m not even sure if you could answer this, but I’ll ask it anyway. What do you think the likelihood is that the AFEs coming in the door will accelerate to the point where you would need to I don’t know that you’d cut your own operated program or that you would need to raise capital?

Craig Rasmuson

Well that’s all the questions we’re trying to answer right now and keep ahead of. We definitely do not want to go non-consent within the Wattenberg. So that is the flex that where we look at our CapEx on our side of what we’re going to drill versus what we’re going to participate in with a majority of our acreage being HPP we’re not forced into developing our own acreage at any certain pace, but on the non-op you’re kind of held captive there to either go or not go and so we’re really, what to say, fairly liquid in order for us to not bypass anything and I will tell you all the operators are being very proactive at this period in time because they’re realizing that some of the smaller less capitalized companies will have trouble keeping up the pace if they’re not notified way in advance. And so Noble actually hired a department just to do that and keep everybody notified as to their existence and then Canada is doing an excellent job of notifying us of their future plans going forward and we have had no contact with Anadarko at this point as far as AFEs on horizontals.

Kim Pacanovsky - MLV & Company

Okay.

Craig Rasmuson

But as we finish 2013 and go into 2014 our number one goal is operator horizontal program.

Kim Pacanovsky - MLV & Company

Okay, got you. Great, thanks. Thanks so much guys.

Operator

Thank you. Our next question comes from the line of Steven (indiscernible) Corporation. Please proceed with your question.

Unidentified Analyst

Hey, guys. How are you?

Monty Jennings

Thanks, Steve. How is it going?

Unidentified Analyst

Good, really well. Could you just give us a bit more color on this Yuma well in Eastern Colorado and the potential opportunity out there and what kind of gas pricing would support a real problem, just a little more color on that?

Edward Holloway

Well gas pricing, we feel that north of $3 definitely and $3.50 particularly makes that play fairly economic. We have a very good position there long-term and we – the drilling and completion costs are so low that you can drill quite a few wells pretty quick point in time. And the trend right now is a lot of these gas utilities and big end users of gas are now looking for joint ventures or some sort of exploration agreement to come in and walk up some of these gas assets so we’re looking at everything possible in that arena going forward and we are basically, we could be booking reserves out in Eastern Colorado area. We have just declined to do so until we get active out there.

Unidentified Analyst

And the Yuma well is spud already or is about to spud, what's the …?

Edward Holloway

The middle of this month, we just haven’t had a report as to -- it's scheduled for April 15th.

Unidentified Analyst

Right. Thank you so much.

Edward Holloway

Thank you.

Operator

Thank you. Our next question comes from the line of Joel Musante with Euro Pacific Capital. Please proceed with your question.

Joel Musante - Euro Pacific Capital

Good morning guys. Most of my questions have been answered. I just had a few clarifications. On the production, just I think you said it was 2500 barrels a day at the end of the quarter?

William E. Scaff Jr.

Including non-operated, Joel.

Joel Musante - Euro Pacific Capital

Okay. What's the average, I guess time that wells are on; is it – are they on 100% -- more or less 100% at the time or is it more or like 80%?

Edward Holloway

It's not really the amount of time that they’re on. It's just what they’re out -- they’re capable of getting into the line at what percentage. And Craig can probably answer a little more into that.

Craig Rasmuson

We looked hard at this last quarter in regards to how the freeze ups and the high line pressures impacted us. We do feel like the freeze ups brought us down about 85% capacity as far as number of days that well should have been running. We were down 15% there. We’ve gotten that rectified here recently, so we’re excited we’re back up to about 97%, 98% as of the last five, six business days we’ve had all wells running minus just a couple that we’re struggling some of our older wells struggling to get into the gas line infrastructure with the high pressures in the neighborhood that they happen to be in. It is – I kind of lost my turn.

Edward Holloway

I mean from the standpoint of the freeze ups and getting that rectified and getting the high line pressure with compressors on every well, these wells cycle, they cycle two or three times a day and so right now going into March we had a 100% production moving forward and so yes we did have some downtime in this last quarter. But going into the third quarter we were wishing for cold weather, now we’re kind of wishing for something a little bit more moderate as we move forward.

William E. Scaff Jr.

It's hard to quantify what the high line pressure is doing to us if you look in an area we got 275 pounds of pressure. If you were at 175 pounds of pressure that well could probably cycle a third, fourth time a day. So there’s certainly an impact with the high line pressure even though the wells are running or certainly being decreased on the potential and as line pressures come down we hit these moderate months DCP turns on this new plant we hope that directly will just help to increase exponentially the existing production we have right along the new drills going forward.

Edward Holloway

It may run every day, but only get one cycle in versus three. So it's just more of the well-by-well basis.

Joel Musante - Euro Pacific Capital

All right. And I only have one other question on the interest cost I didn’t see any interest costs recorded. I’m just trying to figure out like when you incurred your debt was it towards the end of the quarter or was there some other recording method that you use?

Edward Holloway

Yeah, Joel the debt of course the Orr acquisition was early in the quarter. So we carried that balance through most of the quarter. But right now our portfolio of undeveloped properties does qualify for interest capitalization so all of the interest we’re incurring at this time is capitalized into the total cost flow and you won't see it actually in the P&L because of that we do detail that out in the footnote of the 10-Q and that will be it on file shortly, so you’ll be able to see it there, but it's -- at this point it's all being capitalized due to the full cost.

Joel Musante - Euro Pacific Capital

Okay, all right. Good enough. That’s all I had. Thanks.

Operator

Thank you. (Operator Instructions) Thank you. Our next question comes from the line of Jack Aydin with KeyBank. Please proceed with your question.

Jack Aydin – KeyBank Markets

Hey, guys.

Edward Holloway

Hi.

William E. Scaff Jr.

How are you doing?

Jack Aydin – KeyBank Markets

Good. Most of my questions are answered, but I do have one. PDC is operated on two wells and you’ve got a lot of your interest is huge over there. Any result of those wells you’re aware of? One you own a 64% interest the other one is 42%, and both got a Codell information?

Edward Holloway

They just finished completing most, finished the drilling portion of those two wells a week ago. So they are now in the completion stage and I would think that’s going to take another 30 days – probably take another 45 before we started getting any daily feedback on production, but those were both Codell horizontals.

Jack Aydin – KeyBank Markets

Is the cost of those wells in the first half or were going to spill over in the second half?

Edward Holloway

That will be in the second half, those – the drilling in those wells turned out to be a March event, so we’ll record that in the quarter which begins March 1st. And we’re currently PDCs just spotted another well this week, a horizontal Codell that we have 25% in.

Jack Aydin – KeyBank Markets

Okay, one more question. So you’re going to start your first horizontal well and you’re planning to do four wells for the year, is that still on schedule?

Edward Holloway

Yes.

Jack Aydin – KeyBank Markets

Okay. Thank you.

Edward Holloway

Thank you, Jack.

Operator

Thank you. Our next question comes from the line of Richard Dearnley with Longport Partners. Please proceed with your question.

Richard Dearnley - Longport Partners

Good morning. I suppose with the Yume well with the $225,000 cost isn’t testing anything deeper or testing for oil at any point?

Edward Holloway

Not at this point. No.

Richard Dearnley - Longport Partners

Okay. And then on Slide 10 of your presentation the two Pennsylvanian tests one in Cheyenne County in Nebraska and one in Washington, who is drilling those?

Edward Holloway

Chama Resources.

Richard Dearnley - Longport Partners

Okay. And then you mentioned in the release you want to broaden your activities across your asset base and in the release where you’re (indiscernible) Morgenstern one of his tasks is to broaden your overall portfolio. Could you discuss what you’re talking about there?

Edward Holloway

Well really what we’re talking about there is maximizing the value of our assets across our portfolio, and that’s what Ron will be focusing on that could be joint ventures, that could be monetization of some leases, that could be additional exploration agreements like Vecta. We are currently, we’re at a stage of the company where we are being approached with a lot of different opportunities and we have opportunities of our own that we need to put together and Ron will be heading most of that.

Richard Dearnley - Longport Partners

I see. You mentioned on the Yuma well that utilities are interested in JV is that really moving forward suddenly?

Edward Holloway

Well, I think that’s a macro picture. I’m not saying that’s what’s happening with our acreage. But on a macro picture we’re seeing a lot of end users partnering up with exploration companies to develop their oil or their gas portfolio, accelerate the development of it and I think that, that has a potential for us in the Yuma County area with our position there. We have nothing currently working, but that is the macro trend of either utilities or end users who have a high use of natural gas are looking to get in at a very contrarian point in time and lock in these gas reserves for a long period of time, especially long-term gas reserves which are Yuma County acreage has.

Edward Holloway

But there is good takeaway capacity through standard pipeline systems.

Richard Dearnley - Longport Partners

Right. I might talk to the steel mills Nucor here …?

Edward Holloway

Right. Nucor has done a couple of deals.

Richard Dearnley - Longport Partners

Couple of deals?

Edward Holloway

Yes.

Richard Dearnley - Longport Partners

All right. Thank you.

Edward Holloway

Thank you.

Operator

Thank you. At this time, this concludes our question-and-answer session. I would now like to turn the call back over to Mr. Holloway for his closing remarks.

Edward Holloway

Thank you, Ruya. Energy remains well positioned within the Wattenberg Field. Its core area of operations for continued growth and we’re confident in our ability to expand our activity across our asset base as opportunities present themselves. We look forward to keeping you appraise of our progress. Thanks to 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 will turn it back over to you. Thank you.

Operator

Thank you. Before we conclude today’s presentation, I’d 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, indicates 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 their inherent uncertainty.

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 overruns, the Company's costs of production, environmental and 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 August 10, 2012, starting in approximately two hours. Please refer to yesterday'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.

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

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