Synergy Resources' CEO Discusses F4Q13 Results - Earnings Call Transcript

| About: Synergy Resources (SYRG)

Synergy Resources Corporation (NYSEMKT:SYRG)

F4Q13 Earnings Conference Call

November 5, 2013 11:00 AM ET

Executives

Edward Holloway - President and CEO

Frank (Monty) Jennings - CFO

William Scaff, Jr. - EVP, Secretary and Treasurer

Craig Rasmuson - VP, Operations and Production

Analysts

Irene Haas - Wunderlich Securities, Inc.

Welles Fitzpatrick - Johnson Rice & Co.

Ipsit Mohanty - Cannacord Genuity

Ryan Oatman - SunTrust Robinson Humphrey

Joel Musante - Euro Pacific Equities

Jared Lewis - Northland Capital Markets

David Beard - Iberia Capital Partners

Jack Aydin - Key Banc

Operator

Good morning everyone and thank you for joining us to discuss Synergy Resources' Fourth Quarter Results for the period ended August 31, 2013.

With us today are Synergy Resources' President and CEO, Ed Holloway; the company's Executive Vice President, Mr. William Scaff Jr.; and CFO, Mr. Monty Jennings. Vice President of Operations, 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 November 19, 2013. The webcast replay will also be available via the company's website at www.syrginfo.com.

I would 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, Manny, and thanks everyone for joining us today. We issued a press release this morning announcing our financial results for our fiscal fourth quarter and full year 2013, which ended on August 31. This past fiscal year was highlighted by our transition to horizontal development over our assets in the Wattenberg Field, combined with continued production growth from our vertical wells, has resulted in a record revenue this year of $46 million, compared to $25 million in revenues for 2012.

Our operating income grew to $19.5 million in 2013 versus $11.8 million in 2012. During the year, our oil and natural gas production increased 84% over last year, to a total of 772,532 BOEs. This equates to an average of 2,117 BOEs per day, compared to 1,149 BOEs per day a year ago. We also achieved 10% production growth in the fourth quarter over the third quarter, and we reduced our LOE expense to $4.67 per BOE in the fourth quarter versus $5.05 per BOE in the third quarter.

We remain focused on controlling our costs, while continuing to grow our production. In the fourth quarter, we completed drilling five operated horizontal wells on our Renfroe pad. Began drilling the first two wells of six horizontal wells planned on the Leffler pad. The initial horizontal development of our assets, based on the Wattenberg Field has gone according to plan and is under budget. Our participation in non-operated horizontal wells also increased during the year to 21 gross wells, compared to five gross wells in the prior year.

Going forward, production from the horizontal wells will be our primary growth driver. With the remaining liquidity on our 150 credit facility, the $79 million in cash on the balance sheet and the continued exercising of our $6 warrants, we are well positioned to execute on our 2014 capital expenditure budget.

I would like to now turn the call over to our CFO, Monty Jennings, to take us through the details of our financial results for the fourth quarter and full fiscal year. Monty?

Frank (Monty) Jennings

Thanks Ed and good day to everyone. Looking first at our quarterly income statement, revenues rose to $14.7 million in the fourth fiscal quarter of 2013. This represented a sequential increase of 19% from the previous quarter, and compared to the fourth fiscal quarter of 2012, was up 117%.

The year-over-year improvement was mostly due to the 95% increase in average daily production. For Q4 2013, average production was 2,479 BOEs per day. Average production during Q4 of 2012 was 1,270 BOEs per day, an 11% increase in our realized average selling price per BOE contributed to the revenue increase.

During fiscal Q4 2013, our average sales prices were $92.38 per barrel of oil, and $5.06 per MCF of gas, as compared to $82.89 and $2.82 for the year ago quarter. Increased revenues drove a 95% increase in operating income, which totaled $6.7 million during the fourth quarter.

Net income for the quarter was $996,000, a decrease of 49% from the year ago quarter. Net income absorbed significant non-cash charges in the forms of an unrealized loss on commodity derivatives of $3 million, and deferred income tax of $2.3 million, as the value of net deferred tax liabilities was adjusted to reflect the reversal of deferred tax assets recorded for stock based compensation.

Since non-cash charges are not meaningful to management of our daily operations, we often use an analysis of adjusted EBITDA, a non-GAAP term, to focus on cash flow. Adjusted EBITDA increased to $10.6 million in the fourth quarter, an increase of 114% from the $5 million reported a year ago. We continue to generate a ratio of EBITDA-to-revenue in excess of 70%. Please refer to a more detailed discussion about our use of adjusted EBITDA, and it's reconciliation to GAAP in the earnings release, which can be found in the news section of our website.

We designed our commodity derivative activity to protect our cash flow during periods of oil price declines, using swaps and collars, we have hedged 340,000 of future production, covering the remainder of calendar year 2013, all of 2014, and the first six months of 2015. The average price of our swap position is approximately $96.21 per barrel for 2013; $92.13 per barrel in 2014; and $86.25 per barrel for 2015. High oil prices during the fourth quarter produced realized losses of $413,000 and an unrealized loss of $3 million.

As Ed mentioned, full year revenue grew to $46 million, which drove operating income up to $19 million. Both measures are a significant increase from 2012. For the full year, net income was $9.6 million or $0.16 per diluted share, a decline of 21% compared to net income of $12.1 million or $0.25 per share in 2012.

As was the case with net income for the quarter, earnings for the year were reduced for non-cash charges for the unrealized loss on commodity derivatives and deferred taxes. Earnings per share were further impacted by the issue of additional shares from our fourth quarter equity offering.

Adjusted EBITDA, which compensates for the effect of non-cash charges, increased to 86% to $33.8 million from $18.2 million in fiscal 2012. Our EBITDA-to-revenue ratio was 73% for the year.

Now, briefly turning to the balance sheet; as of August 31, 2013, we had cash and short term investments in the bank of $79.5 million, as compared to $19.3 million at August 31, 2012. During the fourth quarter, we reduced the outstanding balance on our credit facility, with Community Banks at Colorado, and ended the year with $37 million outstanding.

The interest rate on borrowings is indexed to LIBOR and is currently at 2.7%. Our borrowing base, which provides borrowing capacity up to $75 million is currently being redetermined by the banks. The new borrowing base will be based upon our August 31, 2013 reserve report, which reported a present value of future cash flows before tax of $236 million.

A number of holders of our Series-C warrants, with an exercise price of $6 per share have exercised their warrants. We originally issued 9 million warrants, and at the end of October, about half of them have been exercised.

From a capital liquidity standpoint, we are well positioned to meet our needs during fiscal 2014. Our sources of cash, which include cash in the bank, cash generated from operations, additional cash proceeds from the exercise of Series-C warrants, and borrowing capacity under our credit facility, should exceed our estimated CapEx of $157.5 million.

I'd like to turn the call over to Bill Scaff, our Executive Vice President, who will provide more detail of our fiscal 2014 capital expenditure plans and the operational aspects of our business. Bill?

William Scaff, Jr.

Thanks Monty. Our solid asset base in the Wattenberg Field continues to generate positive results, both sequentially, and year-over-year. Our initial horizontal wells on the Renfroe pad went according to plan, and we are pleased to announce that the 30-day average production for the three Niobrara C Bench wells was 440 BOEs per day, which was 70% oil. For the two Codell wells, it was 518 BOEs per day, which was 75% oil.

On the Leffler pad, we have finished doing all six wells on the pad, and plan to begin completing the wells in late November, and bring them into production by the end of December. We plan on reporting the 90-day rates on the Renfroe wells, the initial production on the Leffler wells, and the estimated [AFVs] for our operated wells during the next quarterly earnings report in early January.

In the mean time, the rig is moving today to the southern portion of the leasehold in the Wattenberg Field, to begin doing six wells under (inaudible) lease. This, further delineating and derisking our leasehold in the Wattenberg Field. We have revised our CapEx slightly to reflect the lower cost per well, in our operated horizontal program. We now plan on drilling 24 net operated horizontal wells in fiscal 2014, which is four more than originally planned, as a result of the operational efficiencies we are achieving in the field.

We still plan on participating in five net non-operated horizontal wells as well. For further detail on our 2014 CapEx, please see today's press release or view the corporate presentation on our website.

Subsequent to August 31, our fiscal year end, there have been several meaningful events in the Wattenberg Field. First of course is the devastating flooding in Colorado in September, in which thankfully Synergy's employees and assets were largely unaffected. On an operations basis, we had a total of 20 wells impacted by the flood. All of those wells are now back on production, and our first quarter 2014 production will only slightly be hampered as a result. We would like to take this opportunity to thank our field personnel and the service company providers, for their extra effort under difficult circumstances. We are also proud to be a part of the oil and gas industry, which has responded so generously to the release efforts for the citizens and communities impacted by the flooding.

Another development of note at the Wattenberg Field was the mid-October opening of the O'Connor Gas plant by DCP Midstream to ConocoPhillips, our midstream partner. This new plant is very impressive and continues to show the commitments being made to enhance the takeaway and processing capacity in the Wattenberg Field.

We have been active on the leasing and acquisition fronts as well. We have added acreage through organic leasing efforts and participating in state auctions. At August and September, we announced signing letters of intent on two separate acquisitions of assets in the high oil and liquids portion of the Wattenberg Field.

We anticipate closing these acquisitions by the end of December, which will grow our footprint in the Greater Wattenberg area, to nearly 25,000 net acres and 21,000 of those acres in the interior core Wattenberg Field. This does not include our 20,000 net acres in the extension area, and the Northern DJ Basin. This overall acreage position gives us substantial opportunity for future growth.

We remain diligent in keeping our costs down and utilizing our strong balance sheet and liquidity to create shareholder value.

Thank you for your time and interest in Synergy today, and we now 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). Our first question is from Irene Haas of Wunderlich Securities. Please go ahead.

Irene Haas - Wunderlich Securities, Inc.

Yeah, I have a few questions if you don't mind, on your Renfroe wells. The 30-day rate looks pretty good, looks flat, so would like a little more comment on that? And then in terms of total productivity per frac stage and what you see there? And then the next question is the Phelps pad when you drill that particular set, what's the split between Codell and Niobrara?

Edward Holloway

Irene on the Phelps pad, I will start to go backwards here in your questions. We are doing three Codells and three Niobraras on that pad. We have the leasehold there in the whole section, section 32, One North, 66 West, and we originally were going to drill 12 off that pad, but in the interest of trying to keep production going at a quicker rate, we are going to split that between North pad, which is a Phelps pad, and a South pad, which will be the Eberle pad, which is just now in the process of permitting.

And then, on the Renfroe pad, we are seeing that our best wells are a well that we did put 20 stages of fracs on, whether Codell or Niobrara. We had some wells that -- one well that only had 16 stages, and a well that had 17, 18 stages, and we certainly see a proportionate deduct if you will, in the production of those wells.

On our Leffler pad, we were able to put 20 stages of fracs on four of the wells, and 21 stages on the final two wells. So we are excited to see the results with kind of honing in on that 20 plus stage frac for the 4,200, 4,300 foot laterals that we are drilling. Did that cover all your questions?

Irene Haas - Wunderlich Securities, Inc.

Yeah, maybe just a little decline, how do you see your first pad there? I am looking at the 30-day rate, they look sort of flat. Is that what you see?

Craig Rasmuson

We are happy how they are holding in towards the end of 30 days, while we are going on 50 days now for ourselves, as far as the internal numbers we are looking at. We have added plunger lift system on two of them. We are considering on adding gas lift. Also going forward, we are talking to our peers and seeing what the best successes are in that neighborhood. It's obviously a very high oil ratio in the oil to gas ratio, so we need a little extra help lifting and the fact that gas, it's not a prominent gas area. We are seeing that, we are seeing now, we will still get to probably add compression out there, we have the O'Connor plant has helped us immensely, just in the last 10 to 12 days, we have seen not consistent, because they are having startup and shut-in and start-up and shut-in type cycling if you will, at the O'Connor plant. But as that levels out, and we kind of get a true feel on where we are going to be.

It took us some extreme line pressures up in the Eton area to just still high line pressure. We are still over 200, 225 pounds consistently out there, so we think compression is still going to help enhance production, both on the Renfroe and the Leffler pad.

Irene Haas - Wunderlich Securities, Inc.

Thank you.

Operator

Thank you. The next question is from Welles Fitzpatrick of Johnson Rice. Please go ahead.

Welles Fitzpatrick - Johnson Rice & Co.

Good morning. On the C1 Renfroe well, did that well normalize with Southern Niobrara-B? I mean, does it look kind of after the frac, like that might have been a tubing issue, or did that remain well above its (inaudible)?

Edward Holloway

What was the question again?

Welles Fitzpatrick - Johnson Rice & Co.

The C1 Renfroe well, the well that came on at 791, does that end up being more in line with the other two Niobrara wells, or do that continue to outperform, and if so -- I don't believe anything different was done to that well, is that right?

Edward Holloway

No, it has really continued to produce at the level with the others. It was just that the reason it came on with that different IP rate, is that we IP'ed that with tubing and it hadn't flowed up casing. So since then, it has leveled out to pretty much what the other Niobrara wells are doing.

Welles Fitzpatrick - Johnson Rice & Co.

Okay. Perfect. Then on the Phelps pad, and I guess, (inaudible) Phelps in that really. Are you guys still planning on trying on a Niobrara-C?

Edward Holloway

Yes.

Welles Fitzpatrick - Johnson Rice & Co.

And do you think that will be on the first, the Phelps pad or the Eberle?

Frank (Monty) Jennings

It's actually the first well we are drilling outside, and then from there, we will decide -- right now, it's planned out as a C, two Bs, and then the three Codells.

Welles Fitzpatrick - Johnson Rice & Co.

Okay. And then one final one kind of from a higher point of view, with the extra capital you guys have, with the warrants coming in the door, how do you think about accelerating potentially IDM in the second rig, or maybe one in the back half, half in that rig in 2014?

Edward Holloway

We are currently looking at that as we speak. It just allows us flexibility in acquisitions, and/or accelerating with it -- or as you said, a rig and a half in the second half; because we are really, with our cash position, we need to get these wells into production quicker, and we are in negotiations. Bill can speak more about where we are at?

William Scaff, Jr.

We are probably looking at bringing on an ADR rig some time in January that will replace rig 17. Rig 17 will then be used to fill in other pads, where we will be drilling, so as [that stage], and we will probably have a rig and a half. As we move forward, we will continue to contract that second rig on a pad by pad basis, may be sure it was one of the other smaller operators. So that's the plan as we move forward to accelerate from this point forward.

Welles Fitzpatrick - Johnson Rice & Co.

Okay. That's great. Thanks so much guys.

Operator

Thank you. The next question is from Ipsit Mohanty of Cannacord. Please go ahead.

Ipsit Mohanty - Cannacord Genuity

Hey morning folks, thanks for taking my call. Just a more broader question, as you go ahead in pad drilling and given the strength of Codell, it's broadly from the neighbors you have around you, and you from your results published. Do we see a higher proportion of Codell from your pads going forward?

Edward Holloway

We do. Probably as we go forward, it will probably be somewhere around 50-50. We are going to focus on the Niobrara, where the Codell is strong. We are going to probably take that on a 50-50 basis on each pad.

Ipsit Mohanty - Cannacord Genuity

That's wonderful. And then, your well costs are some of the lowest in that area, could you specifically talk about where you are seeing an edge versus others, what are you doing better?

Edward Holloway

I think the main thing is our low G&A to begin with, is the number one factor. Having experienced, skilled people and doing our homework going forward, and our relationship with our leaseholder and landowner, where we really sit down with them and work out a game plan, as to the efficiencies we can have via them, allowing us to maybe pipe water in or do some other things, tighten up the locations.

The one thing I will say is that, we do not cut any corners, instead of doing 16 and 17 stages on the Renfroe, we went ahead and moved those stage patterns up. The incremental costs was not that great, but we went ahead and did that, and I think you are going to see it in the future, even putting these stages closer and closer and together instead of 200 feet, we are going to go to 170, may be 150. Getting more connectivity to the zones that we are in, and going forward.

We use all the latest and greatest fracs. They are very large stage fracs. There is no corners cut. These are really Cadillac styled wells as of today. Things change, as we go forward, but I just want to reemphasize, that it's just really our efficiency and operation that is really creating that value in the field.

Frank (Monty) Jennings

Our G&A is about $465,000 per month, that includes legal and accounting. That's one of the lowest in the industry.

Ipsit Mohanty - Cannacord Genuity

That's impressive. And then finally, before I hop back in the queue, one thing that we don't talk about much. But what is it that, some of the neighbors are seeing in your -- close to your acreage in Nebraska, that you can highlight? Or in other words, what are you -- is there anything that excites you in that portfolio?

Edward Holloway

Well, we are doing a lot of blocking and tackling out there, blocking up some of our -- where possible. We have been active in the state leasing, going forward. Currently, there is 12 rigs working in that area, primarily in the Dundee County area, where we have a large acreage position. There have been some significant discoveries. But the information coming out of Nebraska is very slow. These are small independents. Unfortunately, there is only one public entity that we know of, Four Star. We do know some discoveries that have been made in this area. But nothing that's been released publicly that we could announce.

The other thing I will tell you, that even in our Eastern Colorado block, in the Yuma County area, Washington County, continue to have permitting of other operators, either horizontal or vertical, penetrating the Mississippian and the Pennsylvanian formation. There is a lot of interesting things going on, but nothing public to really speak about. We are really pleased in our position and our long term leases in this area, that allows us to be ultra patient, watching this play unfold.

Ipsit Mohanty - Cannacord Genuity

Got you. Well, I will hop back in the queue. Thank you.

Edward Holloway

Thank you.

Operator

Thank you. The next question is from Ryan Oatman of SunTrust Robinson. Please go ahead.

Ryan Oatman - SunTrust Robinson Humphrey

Hi good morning.

Edward Holloway

Good morning.

Frank (Monty) Jennings

How're you doing Ryan?

Ryan Oatman - SunTrust Robinson Humphrey

Doing well. Wanted to talk a little bit more about these 30-day rates. Can you clarify, were these all post-tubing rates, or do these rates include days, where the wells were producing up by casing?

Edward Holloway

It was a combination on every well, between up-casing and tubing. So it's a combination.

William Scaff, Jr.

Keep in mind, that they don't have plunger lifts yet. They do not have compression equipment yet, which Craig alluded to earlier. So now we'd be putting plunger lifts in, along with compression equipment, to hold those rates up, as they start to decline down.

Ryan Oatman - SunTrust Robinson Humphrey

Okay. I mean, the reason I am asking is, it does seem like, based on the October 1st release, I mean, the well seemed to improve, call it, an average of let's say 50%, once they were put on -- once you had the casing installed. So I mean, do you feel that these rates you provided have room to expand on, say the next batch of wells, if you were to have casing, if you were to have the lift involved, etcetera?

Craig Rasmuson

They are probably going to put tubing in quicker. That's one thing from the standpoint of this particular pad that we learned, is that as we bring them on, we will immediately put tubing in, and then move towards plunger lifts and then move towards compression.

Edward Holloway

What really happened on the Renfroe, as we move on our fifth well, we had a little more -- the rig was on the whole, a lot longer than we had anticipated. So we made the election at that point in time, to go ahead and flow the wells up-casing. We don't anticipate that happening on the next pad. We will go right through, clean-up the well bores, and then turn right around and run to the [intermittent] and for the (inaudible) production.

It was just a circumstance that developed on the Renfroe, where we felt we need to leave that rig on the hole longer, and we had these wells building pressure and trying to get the cash flow and revenue going. We elected to flow them up 7-inch casing versus 2H and 3H tubing, and for the scientists out there, you can do the calculation on hydrostatic weight on wells flowing up 7-inch versus 2H and 3H.

So we prefer to start about on 2H and 3H, absolutely.

Ryan Oatman - SunTrust Robinson Humphrey

Sure. It just seems to be, like certainly those rates should be normalized for that. It would certainly be even further above peers. Moving on, if --

Edward Holloway

I will mention about that is, the key element looking at these wells and their BOE rate, it's always like to have a large number, but you have to look at the quality of the BOE, and when you have 70%, 75% oil versus some areas where it's 50% oil and natural gas, and maybe a higher BOE number, what we are really pleased about is our liquid content coming from the wells and the BOE value.

Ryan Oatman - SunTrust Robinson Humphrey

Absolutely. And it does look like, you all are confident in your well costs to increase your horizontal net well count next year, and cut the well costs from 4.5 to 4 flat. Can you just talk about what's given you that confidence and what you are seeing on these next batch of wells?

Edward Holloway

Well, we are running in line. Operations are going very smoothly. No hiccups. Each pad has it's own unique dynamics. The Renfroe pad, we had to pay, 390,000 in hookup, gas hookup. On the Leffler, we don't have that, though we will probably have to have water costs may be slightly higher than the Renfroe. So we are pretty confident of the bucket of which we can drill these wells, and it's a bucket that's under 4 million.

Frank (Monty) Jennings

We are currently under 4 million, and if we can sustain that through the Leffler's, we will report exactly what that number is, but we want to make sure that we are sustaining it.

Ryan Oatman - SunTrust Robinson Humphrey

Okay. That's very encouraging. And then, one last one for me, lower probability question here, but it does seem like obviously there is substantial uplift production with this accelerated program that you have just set forth here. When do you think you will have enough data on the wells to provide a 2014 sort of production goal for investors?

Edward Holloway

Our next call.

Frank (Monty) Jennings

Early January.

Edward Holloway

I think our next call is January 5th or somewhere around that timeframe, when our next Q is due, and we will definitely give additional information at that time.

Ryan Oatman - SunTrust Robinson Humphrey

Fantastic. I appreciate the help guys. Thank you.

Edward Holloway

Thank you.

Operator

Thank you. The next question is from Joel Musante of Euro Pacific Capital. Please go ahead.

Joel Musante - Euro Pacific Equities

Hey guys.

Edward Holloway

Hey Joel, how are you doing?

Joel Musante - Euro Pacific Equities

Pretty good. Just had a couple of questions. I will start with reserves. You had a pretty good volume increase, but your PV10 was almost double that, so I was just wondering what accounted for that? Was it just prices, or more developed base or was it something else?

Craig Rasmuson

Joel yeah, that well flexed the switch to horizontal. As we switch the reserve report over for more vertical wells to more horizontal, the production profile on those horizontals is quicker. So the differential there between the increase in the reserves and the PV10, is a faster production. So we are getting that to the ground a little faster, that's helping us in that PV10 calculation.

Prices were virtually flat, when you compare the reserve reports from the last two years.

Joel Musante - Euro Pacific Equities

Okay. So was this mainly in your PUD volumes that you saw that increase, or because of -- you didn't have those other wells on, or did they get reflected in reserves as proved-developed non-producing?

Craig Rasmuson

Well, what happens is these horizontal wells that we have in the CapEx program for 2014, they are in that report, either as proved-developed, non-producing or as PUDs. But with a one year time horizon on those 24 wells coming in, that helped us on the -- we showed a big jump in early production.

Joel Musante - Euro Pacific Equities

Okay. All right. And what was the EUR that you are reporting for your horizontal wells?

Edward Holloway

Well I will tell you that the EURs and how they are working is, when we have other operators in the area, the Ryder Scott is taking a very ultra conservative approach to these horizontals, until we get further down the line in history on the wells on the decline curves, and things going on with high volume. So they are low, from what's being reported by other operators. Our production is better. So we are really disappointed in the reserve side of things, not being up to speed as to what's going on, how it's going, and they are taking a very still, a very ultra conservative approach to these horizontal wells. And that being said, in certain cases, where we have [both] the vertical production, like PUDs, some of that reserve is going to be falling off.

So your incremental value is not going to be 100% by everyone's thinking; because some of it, we have booked as verticals going forward. Some of that vertical reserve will be falling off the books, and added with horizontal. We are still not getting the PUD value. We believe that that is not even close for the horizontals. I think it's still going to be a year and a half to 2.5 years out before they really unfold with the PUD value for horizontals, more than one per well and going forward.

Craig Rasmuson

Keep in mind, we haven't drilled a well since last December, and so when we had this reserve report at August 31, which is bringing in these first five wells for just the very initial period. So there wasn't much review there. The February 28th reserve report is going to be much more meaningful for exactly what we are doing operationally, but still very conservative as you stated.

Joel Musante - Euro Pacific Equities

Right. I know that some of the other operators, early on, were reporting or I guess booking like 220,000 barrel EURs per -- so I don't think it's unusual.

Edward Holloway

Right. Well I will say our reserves are ultra conservative, and that really where you need to look at the company going forward is our cash flow, and what we are bringing to the bottom line, irregardless of what the reserve engineer is plugging in at this point in time. I guess, the word is, that we are about totally pleased with their approach.

Joel Musante - Euro Pacific Equities

Okay. All right. Fair enough. Just going to the -- your production numbers are a little higher, but gassier, what accounted for that in terms of production for the quarter?

Edward Holloway

I really couldn't answer that to be honest with you. There is not any one factor that it would account for that. It's just the way things, I guess, came down.

Joel Musante - Euro Pacific Equities

The price seemed like it was a lot higher, do you have any comment on that?

William Scaff, Jr.

Yeah the gas price was influenced, this time by the NGL content. We are reporting on a two stream basis, so that's a blended price per MCF and the area, where we are doing the horizontals, we also have some non-ops with horizontals in that area, which were in the fourth quarter; our horizontals production won't hit till the first quarter this year. But we are seeing some pretty good NGL content coming out of that area.

Craig Rasmuson

These are high BTU wells, and that's what you are seeing.

Joel Musante - Euro Pacific Equities

Okay. All right. Makes sense. Then, do you have a production number, kind of recent -- something we can go off of for first quarter?

Frank (Monty) Jennings

This time, we are not really prepared to give guidance at this point. As we move into the quarter, and as we get into the -- obviously, we are already there. And we will definitely be reporting in early January, where we are at, and we will give guidance at that time.

Joel Musante - Euro Pacific Equities

Okay.

Frank (Monty) Jennings

We got acquisitions coming on, we just got a lot going on right now. So it's not very meaningful, until those are completed. Where we are at on the horizontals; so again, January will be much more correct.

Joel Musante - Euro Pacific Equities

All right, and then just one last one in Nebraska, most of the development or exploration there is in that Pennsylvania formation. Is that something you are prepared to drill some wells in? I know it's more exploratory in nature, is that -- are you waiting for Mississippian wells could be drilled there, what's your approach?

William Scaff, Jr.

Really our approach is to watch what is really occurring. Looks to us that it's a series of pools of oil, so to speak, in the Pennsylvanian, where significant discoveries are next to our leasehold. We are prepared to move operations in that area and explore, but we are waiting. Very pleased, that there is that many rigs working out in that area, and there is a lot of articles coming out of these small little communities, local papers, talking about the oil boom out there, and that's not the only ones talking about.

There are significant wells being drilled, 3-D has really enhanced that play tremendously. I think you will be seeing us in the coming years, start to playing at least some science in 3-D and some of our large lease blocks, because that's what we have in that areas, very large lease blocks, that's really designed around a 3-D development going forward.

So we have got -- really, we are watching. We got our ear on the railroad tracks and we go George, guide them down the dirt roads, George Seward is our Director, lord of Directors, assembled the majority of that play out there. We are very encouraged today, and it just keeps increasing going forward.

So on the Mississippian, really, we are not anticipating anything there. That's discovered, that's just icing on the cake as far as we are concerned.

Craig Rasmuson

There's nothing in our area in our 2014 CapEx budget, possibly 2015, as we continue to watch.

Joel Musante - Euro Pacific Equities

Sounds good. All right. Thanks a lot.

Edward Holloway

Thank you, Joe.

Operator

Thank you. The next question is from Jared Lewis of Northland Securities. Please go ahead.

Jared Lewis - Northland Capital Markets

Good morning guys.

Edward Holloway

Good morning Jared.

Jared Lewis - Northland Capital Markets

Just on the data you have so far in the Renfroe, and what you are seeing, are you prepared at all yet, or when do you expect to kind of put a tight curve out on those horizontals?

Craig Rasmuson

We will have that by year end, by December, and again, reporting that in January.

Jared Lewis - Northland Capital Markets

Okay. And as you kind of zero-in on, what you learned on the Renfroe, are you anticipating, basically the exact same frac design, everything going forward from here across -- just that you keep rolling this out 2014?

Edward Holloway

I think we are having many discussions with Halliburton and their engineering staff. I think we are very comfortable with the amount of sand that we are using and the types of fracs that we are using. I think you are really going to start seeing, across the industry, and with us, more staged -- less shorter intervals between fracs, and trying to maintain within the zone and going forward. We are very encouraged with, just on our Renfroe, that the difference that we are seeing between 16 and 20. And on the Leffler, we had four wells with 20 stages, and we are able to squeak one extra stage in on the last two, so we had 21 stages.

And it looks like right now, in the preliminary planning, we may go as high as 25 to 28 on our Phelps pad. I think Anadarko is, we have been moving in this direction as well as in others. I think there has been some other comments by Whiting on plug and perf, business it's similar design, more fraction, a little bit smaller, high sand concentration. So we are on top of that side of it, and very encouraged, and that's the key to where we are in our development, that we are down the road a long ways from what the pioneers of the horizontal, the one where you started out with, and it's a fast moving changing environment continually, and we are on top with all our service providers.

And that's why you want to use the best of breed in any way, because they are on top of that side of it, and we have that in our Hanson drilling in Halliburton.

Jared Lewis - Northland Capital Markets

Thanks Ed. That's very helpful. And just on that, obviously, you mentioned waiting lot of activity up in there, Red Tail, which is just north of your Morgan County acreage. Any plans on what you are going to do with that going forward here?

Edward Holloway

Well we are planning a test well. We are going through a permitting there, vertical test well to test the J, D-Sand, Green Horn and Niobrara. We don't think there is any Codell there in the first test well. Whiting moving in their last acquisition of over 30,000 acres. Moved closer to us by two townships, which is tremendous. We have got Bill Barrett, Bonanza Creek to the west of us, along with a small operator out of California or Texas condor.

Everything just keeps moving our way, but there are lot of things developing out there, where I think the parameters are changing continually as to what makes a good well, and we are really anxious to get out there and do something, but we are going to be more patient. We are really watching infrastructures being built out. All the ingredients you need for quick cash flow, and that's what we are looking for, before we really put out any large amount of CapEx in this area. We are getting there, but we are not ready to move yet.

Jared Lewis - Northland Capital Markets

Excellent. Well that was a good strategy, the first go around. So that's all I have, and thanks a lot.

Craig Rasmuson

That one well will be drilled in 2014, that Ed was talking about.

Operator

Thank you. The next question is from [John Jung] of Arrowhead Asset Management. Please go ahead.

Unidentified Analyst

Good morning. You have answered most of the questions I had, but could you confirm you are using plug and perf on these wells on your completions?

Edward Holloway

No, we are using swell packers and sliding sleeves. Currently right now, in the Wattenberg, the only people that we are aware of using plug and perf, are the operators who have had a problem in the drilling of the well, which requires a plug and perf type of completion, because of the difficulty of getting swell packers into a well, which may be drilled a little quicker, that are off target. We are not aware of anybody in the Wattenberg going to that type of completion.

Now out in the extended area, Whiting is definitely making a move with that, and we are watching that very carefully. Going forward our thoughts are either going to go with a lot more stages with swell packers, sliding sleeves or we are going to go with, switchover to a plug and perf and be doing may be 30 stages at a time.

Unidentified Analyst

Higher sand? They have increased their sand dramatically in the last quarter?

Edward Holloway

Yeah, and so did we. We started out there. So we are right on that page.

Unidentified Analyst

Okay. Well thanks for that info.

William Scaff, Jr.

Plug and perf has seen more than emergency procedure, where you are having problems with the slide sleeve and then they will flip to plug and perf.

Unidentified Analyst

Okay.

Operator

Thank you. The next question is from David Beard of Iberia. Please go ahead.

David Beard - Iberia Capital Partners

Good morning gentlemen.

Edward Holloway

Good morning David.

David Beard - Iberia Capital Partners

As the drill Renfroe -- I am sorry in Phelps, what percent of your acreage you think could be de-risked at that point?

Edward Holloway

I am sorry, what was the question?

David Beard - Iberia Capital Partners

What percent of your acreage would be de-risked after you drilled the first three horizontal pads?

Edward Holloway

Well in the core Wattenberg, the company's view is that all our core Wattenberg is de-risked. We do have 5,000 acres on the perimeter of the Wattenberg, that we would like to see a little more de-risking of, but everything in our core, which is approximately a little over 20,000 acres at this point in time, we classify it in-house as de-risk.

Also drilling down south and one north, that will give us a much better view of the higher EUR area. So we will see the lower EURs from a Renfroe-Leffler's that we have drilled to start producing, and we are going to be about as far south, as anything we have in our leasehold on this next pad. Albeit, there is other activity for major operators, right in the same neighborhood. So we feel like it's already de-risked going in, and it's also going to render one straight C-Bench only on this pad also, sort of (inaudible) de-risk between C and B bench too.

David Beard - Iberia Capital Partners

Okay, that's helpful. Thank you.

Edward Holloway

Thank you.

Operator

Thank you. The next question is from Ipsit Mohanty of Cannacord Genuity. Please go ahead.

Ipsit Mohanty - Cannacord Genuity

Thanks for taking my follow-up. Really, just sticking to the fact that there was in -- the production mix right now looked a little more gassier than your recent well going forward? Is that due to the vertical wells that you have drilled, or is that due to normal wells, could you comment on it?

Edward Holloway

I don't understand the question?

Ipsit Mohanty - Cannacord Genuity

For the production mix that you see right now --?

Edward Holloway

(Inaudible) on everything?

Ipsit Mohanty - Cannacord Genuity

Overall, yes sir.

Edward Holloway

Well, what we are seeing in the Renfroe is a definite, more oil and less natural gas. I will tell you, the Renfroe area is going to have a very high BTU rated gas, so I think our NGLs are going to be greater than any other area. From area to area, it's going to change, but our vertical there, across all our leasehold, what we are seeing in the horizontal, is just a little bit stronger oil presence going forward. So with us drilling down south, in the southern part of our leasehold position, we get a better feel for that, and then we will probably move over to our western side, and really get a strong feel as to what we are seeing from an oil and gas mix, versus what we are seeing from the verticals in that same area.

It's a little too early to give a real conclusion to that.

Craig Rasmuson

And we are still about 55% oil, 45% gas, and that's still the range we have been in.

Edward Holloway

And I think the misleading thing is, we are reporting two stream (inaudible). For almost every well, a lot of the other operators are doing a three stream, in order for them to make it look more liquivite in their presentation. It still doesn't mean there, as you report three stream or two stream, at the end of the stream, the cash flow is the same.

Frank (Monty) Jennings

In the fourth quarter, all the increase came from non-operated wells. We did not bring a well on-stream during the fourth quarter. That pad was finished right at the end of August, and started production in the first week in September. So the little bit of shift there in the fourth quarter, really was coming out of non-op wells.

Ipsit Mohanty - Cannacord Genuity

And my last one, forgive me if I missed this, I am a little early on this, but have you given a PDP and PUD split of your proved reserve please?

Frank (Monty) Jennings

Yes, it will be in the PowerPoint.

Ipsit Mohanty - Cannacord Genuity

Okay. Thank you.

Edward Holloway

Thank you.

Operator

Thank you. The next question is from Jack Aydin of Key Banc. Please go ahead.

Jack Aydin - Key Banc

Hey guys, most of my questions have been answered, but just one quick. When you guide from 16, 17 stages later say to 21 to 28 or potentially 30, are you factoring any -- I mean, your well cost is you know, keeping it 4 and less, what you think the uplift in costs could be, if you go from the 17, 18, 20, whatever it is, third stages. What do you think your well cost uplift could be? Or nothing?

Craig Rasmuson

No, you have an incremental cost obviously per stage. It's nominal in the big picture. A lot of it is getting the equipment and the horsepower on locations. It's not that much the water is already piped to you, it's already coming to you. You have a little increase in some of the profit costs, but we will still be well -- keeping our AFV under 4, like we have been working so hard to do.

I would say, if we went from 16 all the way to -- I haven't priced all the way up to 30, we have priced to 24, 26, and that incremental cost is between 200,000 and 300,000 per well. So we are still very confident of holding that strong AFV.

Edward Holloway

Since we are already there, we will get some economies of scale by having those additional fracs.

Jack Aydin - Key Banc

I assume, you are not doing any cement liner on your wells now, are you? Or are you not?

Edward Holloway

No, not at all.

Jack Aydin - Key Banc

Not at all. Okay. And if you do, similar to Whiting, I assume you are going to do similar cement liner or not?

Edward Holloway

No.

Craig Rasmuson

I mean, if we were going to do it, we would do it similar to what Whiting has mentioned, but we are not planning on doing that at this stage.

Jack Aydin - Key Banc

Okay. Thanks a lot.

Edward Holloway

Thank you, Jack.

Operator

Thank you. The next question is from [Mario Motelli] a private investor. Please go ahead.

Unidentified Analyst

Good morning gentlemen.

Edward Holloway

Hey Mario, how are you doing?

Unidentified Analyst

Good. Directed to Bill, from an investor's point of view, the warrant activity I understand is halfway through the progress of helping the company. Will that continue, could you care to comment on the type of activity, and the volatility of the stock? Wunderlich Securities now project $14 a share, and today we are in a real volatile area. If you commented on the whole activity itself without incriminating yourselves?

William Scaff, Jr.

Well I can't say what Wall Street is doing, but obviously our stocks range from $10 to $11. The warrants are $6 based upon that, and we are moving forward as a company, I think just under $26 million in warrants have been exercised. We continue to see those come in daily, and that is very much enhancing our program, as we move forward in 2014 and 2015 program, by bringing in that additional $54 million. So that has helped a lot. We are excited about that. Again, I can't really comment on the stock price, and where that's going in the volatility of it, it's kind of Wall Street doing what they do. But we are excited about we are growing the company, and how we are funded for 2014 and how we are starting for 2015.

Keep in mind, as these wells come on, we are internally generating a lot of cash flow going into this first quarter. So between internally generated cash flow, our line of credit, and the warrants, we are very well funded for 2014 and 2015 as we move into it.

Unidentified Analyst

Thank you very much. I appreciate and please keep up the good work.

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 to Mr. Holloway for his closing remarks.

Edward Holloway

Thank you, Manny. Synergy is moving into a horizontal development of it's assets in the Wattenberg Field at an opportune time, as continued technology advancements in the field are producing attractive rates of return on invested capitals. We remain focused on growing and developing our Wattenberg assets to provide for the future growth of the company. Thanks everyone for joining us today, and for interest in Synergy Resources. Please don't hesitate to contact us, if you have any further questions.

Manny, you can now conclude the conference call, and I will 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, 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, 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 the 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 November 19, 2013 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.

This concludes today's teleconference. Have a wonderful day.

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