Synergy Resources' (SYRG) CEO Ed Holloway on Q3 2014 Results - Earnings Call Transcript

Jul. 9.14 | About: Synergy Resources (SYRG)

Synergy Resources Corporation (NYSEMKT:SYRG)

Q3 2014 Results Earnings Conference Call

July 09, 2014, 12:00 PM ET

Executives

Ed Holloway - President and Co-CEO

Monty Jennings - CFO

William Scaff, Jr. - Co-CEO

Craig Rasmuson – COO

Jon Kruljac - VP, Capital Markets & IR

Analysts

Ryan Oatman - SunTrust Robinson

Irene Haas - Wunderlich Securities

Mike Scialla - Stifel

Welles Fitzpatrick - Johnson Rice

Kim Pacanovsky - Imperial Capital

Michael Kelly - Global Hunter

Joseph Reagor - Roth Capital Partners

Jeff Grampp - Northland Capital Markets

David Beard - Iberia

Joel Musante - Euro Pacific Capital

Steve Emerson - Emerson Investment Group

Richard Dearnley - Longport Partners

Operator

Good morning, everyone, and thank you for joining us today to discuss Synergy Resources' Third Quarter Results for the period ended May 31st, 2014.

With us today are Synergy Resources' Co-CEOs, Ed Holloway and William Scaff; and CFO, Monty Jennings. COO, 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 would like to remind everybody that today's audio conference call will be available for replay through July 16th, 2014. 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 Co-CEO of Synergy Resources, Mr. Ed Holloway. Sir, please proceed.

Ed Holloway

Thank you, Brenda, and thanks everyone for joining us today. We issued a press release this morning announcing our financial results for our fiscal third quarter ending May 31st.

Production rate in the third quarter of the fiscal year represented the impact of horizontal drilling for the company as we averaged over 4,100 BOEs per day during the quarter. This production led to a 108% increase in revenue to $25.7 million, compared to $12.3 million in the year ago period. Operating income grew by 131% to $11.3 million.

During the quarter, our oil and gas production increased 83% over last year, approximately 380,000 BOEs with a majority of that production coming from horizontal wells.

Encouraged by the results of our first 16 operated horizontal wells, we're increasing the pace of our development in the Wattenberg Field. We finalized an agreement with Ensign Drilling Company of North America to add a third rig to our fleet beginning in August.

The third rig will be an ADR rig powered by natural gas and will initially be contracted to drill eight wells on our Wiedeman pad, four of which will be 9,000-foot extended reach laterals.

In anticipation of adding a third rig to the program, we have increased our permitting activity and currently have 50 horizontal permits approved and another 104 permits in process.

Our enhanced drilling program is setting the stage for a rapid production growth coming online in fiscal fourth quarter ending August 31st and into fiscal 2015.

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

Monty Jennings

Thanks, Ed, and good day to everyone.

Now, turning to our income statement, our revenues totaled $25.7 million in the third fiscal quarter of 2014. The year-over-year improvement was due to the 83% increase in production. The increase in production was accompanied by a 14% increase in our realized average selling price per BOE.

During fiscal Q3 2014, our average sales prices were $90.91 per barrel of oil and $5.15 per Mcf of gas, as compared to $83.98 per barrel of oil and $4.76 per Mcf of gas for the year ago quarter. Overall, the average price per BOE increased to $67.72.

Negative pricing pressure diminished in the Wattenberg Field since last winter when there was a spike in quoted oil price differentials. Quoted differentials have subsided somewhat from the peak but are still higher than a year ago quotes.

Our current oil differential is $10.53 per barrel, an increase of $1.24 from the $9.29 received one year ago.

Our operating income increased to $11.3 million from $4.9 million in the third quarter of last year. Net income increased 98% from the year ago quarter. It totaled $7.2 million or $0.09 per diluted share versus $3.6 million or $0.06 per share a year ago.

Adjusted EBITDA, a non-GAAP measure, increased to $18.9 million in the third quarter, which represents 74% of revenue and is a 103% increase from the $9.3 million a year ago.

Please refer to our more detailed discussion about the use of adjusted EBITDA and its reconciliation to GAAP in the earnings release which can be found in the News section of our website. We continue our efforts to maintain low overhead structure. And on a BOE basis, we're able to reduce G&A costs by $2.18 per BOE.

Now, briefly turning to the balance sheet. As of May 31, 2014, we had cash and equivalents totaling $48 million, as compared to $79.5 million at August 31, 2013, our fiscal year end.

As a result of the redetermination based upon the most recent reserve report, the borrowing base increased to $110 million. With $37 million outstanding on the credit facility with Community Banks of Colorado as of May 31st, the available liquidity is $73 million. The current interest rate is 2.5%.

We increased our commodity derivative activity during the quarter to mitigate short-term price fluctuations in the price of oil and natural gas. Using swaps and collars, we have hedged oil and gas quantities, covering a portion of our production through May 2016. We have not hedged any of our NGL production.

For oil, our average floor prices range from $75 to $87 per barrel. And our average ceiling prices range from $92 to $99 per barrel. For gas, the average floor prices approximate $4.10 and the average ceiling prices approximate $4.51.

During the quarter, posted prices were higher than our hedge position and produced a realized loss of $800,000 and an unrealized loss of $200,000.

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

William Scaff, Jr.

Thanks, Monty, great numbers.

Our two rig horizontal program hit full stride at the end of our fiscal third quarter with five wells on our Phelps pad coming into production in May. The Phelps wells continue to outperform the Renfroe wells during their second month in production.

Subsequent to the quarter end, the six wells on the Union pad began producing in mid-June. With this new production coming online, we exited the last seven days of June with production of approximately 6,500 BOEs per day.

We have finished drilling four wells on the Kelly Farms pad and six wells on the Eberle pad with the rigs scheduled to move to the Kiehn pad and the Weld 152 pad per our operations update press release we issued two weeks ago.

Both Kelly Farms and Eberle are scheduled to begin completion the third week of July. We anticipate that Kelly Farms will begin production by mid-August and Eberle will be producing by late August or early September.

We're allowing a longer timeline to complete the Eberle wells, given there are six wells on the pad, four of which are plug and perf wells and two of the plug and perf wells being 7,000 foot laterals.

With the addition of the third rig, we plan to spud eight wells on the Wiedeman pad during August utilizing a batch drilling process. Earlier in the year, we had projected drilling and completing 34 gross horizontal wells during fiscal 2014, but had mentioned during our quarterly conference call in April that we had fallen behind our original timeline due to weather and drilling delays.

We were able to secure another ADR rig from Ensign in April and drilling operations have become more efficient. We anticipate that we will spud 35 gross wells by fiscal year end and have 20 to 26 net wells on production.

Also, we've modeled participating in nine net non -- five I'm sorry, also, we have modeled participating in five net non-operated horizontal wells during the fiscal year. And now it appears that only three net non-op wells will contribute to production by fiscal year end.

Given these differences in both the operated and non-operated aspects of our drilling program, we now believe we will exit August with a production rate between 6,500 and 9,000 BOEs per day, depending on when the Eberle wells come online.

We continue with our leasing efforts in the D-J Basin and Nebraska. We have 27,386 net acres in the Greater Wattenberg area, 25,765 net acres in the Northeast Wattenberg extension area, 63,478 net acres in the Niobrara dry gas play in Eastern Colorado, and 172,623 net acres leased in Nebraska.

We have also purchased several parcels of surface real estate to use as pad sites in our core Wattenberg leases, giving us greater operational flexibility in key areas of the field.

We've laid out our preliminary development plan for fiscal 2015 which begins September 1st and we will once again be very focused on development of our core Wattenberg assets with three rigs running to begin our year.

Our initial CapEx budget for fiscal 2015 is $200 million to $225 million. We plan on funding the budget with internally generated cash flow, access to our recently expanded credit facility of $110 million and proceeds from the remaining $6 warrants, which expire December 31st, 2014.

About 95% of our fiscal 2015 expenditures will go towards drilling and leasing in the Greater Wattenberg area. We also plan on drilling one or two horizontal wells in the Northeast Wattenberg extension area, targeting the Greenhorn and/or Niobrara formations.

In our Nebraska acreage, we're evaluating drilling locations while we continue to monitor the activity and results of other operators. Lastly, we will watch what the gas futures markets look like coming this winter and if we can hedge the gas at satisfactory prices, we may commit capital to Eastern Colorado which provides a low risk option for future development.

We remain diligent in controlling costs as shown with our recent results at the Phelps pad which averaged 26 frac stages per well and completed well costs were $4 million per well. We are extremely pleased with the early production from the Union well which averaged 21 frac stages and we estimated the completed well costs will be less than $3.8 million.

On the Eberle pad, we estimated the two 7,000-foot lateral wells will have between 40 to 45 frac stages each and the completed well costs for these mid reach laterals will be approximately $5.5 million. The testing of different completion techniques on wells on the same pad is providing us with valuable information that we are applying to our ongoing drilling program.

So thank you for your time and interest in Synergy, and we will 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)

And our first question comes from the line of Ryan Oatman of SunTrust Robinson. Please proceed with your question.

Ryan Oatman - SunTrust Robinson

Hi. Good morning.

Ed Holloway

Good morning.

Ryan Oatman - SunTrust Robinson

It looks like price realizations came in a little bit better than we expected. Is that 10.50 or so discount a good number to use moving forward do you think, or should we look for discounts kind of in the low-teens like you talked about before?

William Scaff, Jr.

No, I think basically we’ve consolidated the majority of all of our production back to Suncor. We have contracts with Suncor through December, currently at 5,000 barrels per day, and we can increase that between now through December. And at this point in time, we are locked in at NYMEX minus 10.50.

Ryan Oatman - SunTrust Robinson

It’s great.

William Scaff, Jr.

And I can tell you in the open market that's an outstanding price based upon transportation cost with regards to rail.

Ryan Oatman - SunTrust Robinson

Okay.

William Scaff, Jr.

So, it’s great to have a refinery in our backyard.

Ryan Oatman - SunTrust Robinson

For sure. And then kind of looking at the broader M&A environment, can you speak to your appetite for acquisitions in this environment and kind of what you have seen out there in the areas in which you operate?

Ed Holloway

This is Ed. We are always evaluating acquisition candidates. But with oil prices at all-time highs for an average for the year, we are very, very careful as to how we make those approaches. They have to fit a very tight criteria. And at this point, we are just continually evaluating the acquisition candidates that are out at this time. But -- and we are very cautious during this period of time.

Ryan Oatman - SunTrust Robinson

Okay. That makes sense. And discipline there. Does the, you know, kind of hot M&A market, does it kind of change your strategy? Would you stay in the Wattenberg Field proper, would you perhaps consider something in kind of the northeast extension we commonly think about or perhaps further north would appears like the Codell is heating up?

Ed Holloway

Well, I think, we are -- we have got our focus on all three of those locations. The northern area, on the Colorado, Wyoming border starting to heat up with horizontals in the Codell where the Niobrara hasn’t panned out as well, looks encouraging there. We are looking at other areas. We are looking at Codell and other areas as well where maybe the Niobrara is not as strong.

There are more blocks of acreage in the extended area that are coming due in the next year to two years that not everybody can defend their position out there. And as we have talked in the past, the toughest way to defend your position and the acreage is drilling horizontal on pads and instead of drilling one well and holding acreage, where everyone is drilling five, six, seven wells. So it’s very expensive to defend your acreage. And so there is a lot of movement going on right now with maybe one year left on lease term. So we are really watching that very closely. And we are watching the Codell development and other areas.

Ryan Oatman - SunTrust Robinson

And it sounds like those areas are not just -- to the north, it sounds like maybe there is some other areas that we need to be paying attention to as well?

Ed Holloway

We are paying attention to all areas.

Ryan Oatman - SunTrust Robinson

All right. I leave it at that. Thanks guys.

Operator

Thank you. And our next question comes from the line of Irene Haas with Wunderlich Securities. Please proceed with your question.

Irene Haas - Wunderlich Securities

Yes. Good morning, everybody. If I may, two questions. Firstly, you know, CapEx of $200 million to $225 million, is that including really three rigs for the entire fiscal 2015 that is reassuming that you wouldn’t renew the third rig sort of in the long term contract? And do you have an appetite for a fourth rig?

And the second question is to get to the high end of your exit rate, say 9,000 barrels a day, what has to go right to get there? That's all I have.

Ed Holloway

Well, Irene, I think that what needs to go right is just timing as to when wells come on, when we get them fracked, how long the process takes? And that's just been the whole theme this whole year.

And if you really look at our non-ops where we have projected five and looks like five will be drilled, maybe more. But net to us -- but everybody is running behind time in the basin. From what they have told us to what is going to happen, it’s part of the business and everybody is running behind time.

The good thing about it is generally during the summer months the timing is a lot better than it is during the winter months due to crop seasons and what not. It slows down a little bit and then people seem to be more on track going forward for that.

On CapEx, as we have done in the past, we have generally come out with a CapEx and then we review it quarter by quarter and we increase it going forward as needed. So I think the answer to that is you will see what we have done in the past, we will probably increase CapEx, and maintain three rigs. And we will be probably be [spudding] [ph] a fourth rig every so often in certain areas depends how it comes about.

But we are very pleased today to have three ADR gas driven -- natural gas rigs in our portfolio and our drilling program. It’s really taken the company to the next level of technology and efficiencies going forward.

Irene Haas - Wunderlich Securities

How many days, if you don’t mind telling me, how quickly can you drill a standard lateral anyway with these automated rigs?

Craig Rasmuson

Once you have gotten the lateral, it goes very quickly. It's setting the surface and the intermediate casing and waiting on cement. So the batch drilling process that we are evolving to will help expedite that. But the best well we just did on the Kelly Farm pad was just over 10 days and that was from spud to TD and placing the liner and so before the rig moves.

So that's very, very efficient. If we can keep hitting those marks, obviously we can over time we'll make up for the time of early 2014's delays that we had on the Phelps pad et cetera. But the basin is just getting better across the board and these ADR rigs through the batch drilling will certainly make us more efficient.

Irene Haas - Wunderlich Securities

Okay. Thank you.

Jon Kruljac

Irene, this is Jon. Just one thing on that that Kelly Farms well that Craig mentioned was a sliding sleeve. The plug and perfs take longer. We are still internally modeling for 15 days spud to spud on average.

Irene Haas - Wunderlich Securities

Okay. Thanks.

William Scaff, Jr.

Irene, I think you have seen some improvement in the timing. Our first production pad was last September. The second was January. The third was May. The fourth was June. And now we have the next two coming up, one early August and one end of August early September.

Irene Haas - Wunderlich Securities

Thank you.

Operator

Thank you. And our next question comes from the line of Mike Scialla with Stifel. Please proceed with your question.

Mike Scialla - Stifel

Hi, everybody. Sorry if I missed it, but Bill you mentioned the $200 million to $225 million fiscal 2015 budget. Did you have a production forecast with that?

William Scaff, Jr.

No, we don’t. Not at this point in time. As we move forward, we will continue to look the $200 million to $225 million. It is pretty much all drilling and leasing, does not include any acquisitions, does include non-operated wells that we think are going to be coming on. But at this point in time, we have not put out a forecast on production.

We'll continue to monitor that, see exactly where we end up at the end of this fiscal year. And as we go into next year knowing our growing budget we will start to look at forecast for production.

Mike Scialla - Stifel

Okay.

Ed Holloway

We want to make sure we have this one at the end of this fiscal first.

Mike Scialla - Stifel

Yeah, understood. Sounds like you -- I guess, I'm trying to read between the lines here, maybe some encouragement on the Greenhorn with possibility of drilling some wells there next year. Anything you can say on the Buffalo Run well, what you've seen, you have half the quarter to fully analyze at this point or what can you say there?

Ed Holloway

Well, I think what we can tell you is, what we've seen to this point is encouraging and we are doing additional testing even go further on the Greenhorn. We should have that in the next four to six weeks, the final determination going forward. But we are running a gauntlet of tests throughout that whole core and today it looks very encouraging.

William Scaff, Jr.

The initial tests are back; as I'm sure everyone saying, well, how long does this take? The initial tests are back. But now we are running some additional tests and that’s going to probably take another 30 days. But we have enough information. We're probably going to start to meet next week and start to talk about how we're going to proceed on the possibility of a Greenhorn horizontal.

Mike Scialla - Stifel

Is there a possibility to drill both Greenhorn and Niobrara there?

William Scaff, Jr.

Yes.

Mike Scialla - Stifel

Okay.

William Scaff, Jr.

And we are strongly looking at both.

Mike Scialla - Stifel

Very good. And then, any thoughts on what's going on with the -- we haven’t heard much recently in terms of the setback issue and more local control. Any thoughts on where that’s going and how that might affect you?

William Scaff, Jr.

Well, we do know is that by, I think, the first week of August we will know exactly what's going to be on the ballot initiative going forward. There is a lot of talk that Governor is trying to broker deals. But we are bracing for November an election and where it's going to be.

And we think that probably three to four amendments might hit the ballot and the setback line from what we've seen, and we haven’t seen the final by any means, is we're budgeting and planning now to mitigate any -- not any but mitigate as much as we can of areas that we may have potential setback issues going forward.

So without really knowing what's going to hit, it's hard to say. But I will say that the way these ballot admissives are coming out we have more people, more industries on our side of the ledge are coming forward, because it's going to affect a lot of different industries. And I think it's going to -- you're going to see a very strong campaign. But it is our number one risk element, out biggest bump in the road for the rest of this year.

Ed Holloway

But first to start it off it’s a fracking ban. They backup that, now it’s a setback where you can't get waivers. I think Craig will concede -- talk about that from the standpoint of being -- today any waivers we have to get, we've been able to get. And I think as we go forward whether its 1,500 or 2,000 feet, we still feel confident that we can get those waivers.

However, we hope that we don’t even have to deal with that issue and that we can beat the ballot initiatives once we know exactly what they are. But they keep getting a little bit softer as we go and battle the storm.

Mike Scialla - Stifel

Got you. Okay. So, if I understood you correctly, if it turns out that say 1,500 to 2,000 foot that gets approved, that’s still not a huge issue for you, you can probably move locations around where you need to or get waivers to drill what you want?

Craig Rasmuson

This is Craig. And obviously I have my hands on the permitting every day. We are presently in the process of working -- we've got 50 permits besides the wells we've already drilled we're getting our next 100 plus permits. And in the next weeks to few months, definitely before the November election, and then we've employed a third-party also to help us get the next round of 100 permits and these are all areas that a setback would go ahead and impact the ones we're keen and eyeing in on for that focus, and with -- even with the ability if we needed to a waiver at that point in time.

But what we are hearing is if a amendment -- if a ballot issue does get put on and it does get bolted in, obviously, I think its grandfathered prior to November is good for two years. So that was the case on all the previous changes to the oil and gas commission setback rules to any other rules that have changed over the last six years with the oil and gas commission, it's always grandfathered from a date.

So if that’s the case we will have, hopefully, in our inventory up to 250 permits that are most challenging with setbacks already in place for drilling program for the next 24 months going forward.

Mike Scialla - Stifel

Okay, great. Thank you very much.

Craig Rasmuson

Thank you.

Operator

And our next question comes from the line of Welles Fitzpatrick with Johnson Rice. Please proceed with your question.

Welles Fitzpatrick - Johnson Rice

Good morning.

Ed Holloway

Hello, Welles. How you doing?

Welles Fitzpatrick - Johnson Rice

Good, good. On the Union wells it sounds encouraging both on the rate and obviously on the cost getting us back under four. I know you guys don’t have the 30 days on them. But can you talk a little bit about the GOR that you are seeing in the flow back today?

Craig Rasmuson

How detailed do you want me to give? I'm asking the bosses how much I can tell you. I will say this that they are mirroring at least the first 15 days of production. We did have to flare 1.34 there and we flared little bit on Phelps to help clean those wells up and we've seen nice results from our experience on Leffler with not flaring and that DCP issue we had back at the start of the year so.

So lesson learned, but it's become a practice, if you will, of the industry to get your wells cleaned up properly and get them down line and its increased production after the first five to seven days, 10 days of flaring that gas.

The gas continues to increase here in week two, going into week three. The oil numbers are very much in line with what we had on Phelps initially. So we're very encouraged. And the gas is increasing at a higher rate, so we're going to be curious to watch what that oil does the first 30, 60, 90 days, does it decrease as gas goes up or well sustained. Obviously, we hope it sustains.

William Scaff, Jr.

Both sides are very, very strong. They are still cleaning up. We are still producing some of the flow back water. But it's very encouraging what we are seeing.

Ed Holloway

Yeah. Well, the other thing, I think, needs to be mentioned here is that. due to the area that we were drilling in, we had some really, instead of -- we had some formations that we were at about 45 degree that flatted out to more 20 degree angle, we clearly reduced the length of our laterals that we could drill there and stay in zone. And that’s why you are seeing 21-stage fracs going across there, but production is -- we're really, really pleased with the production.

Welles Fitzpatrick - Johnson Rice

Perfect. Sounds good. And then one more if I could. The down spacing tests that you guys have talked about doing, is that on the books? I thought that it been the Kelly Farms, but I think I'm mistaken. We can have a way out of it?

Craig Rasmuson

We've actually after we drilled the Phelps pad, which is on a 330-foot spacing pattern, which is about 12 wells per section. We've quickly moved to a 220-foot spacing between horizontal laterals and we started that on the Eberle and the Union and we are very, very encouraged what we are seeing from the Union at this point.

Ed Holloway

We will have more true results because, yes, Eberle and Kelly Farms, the two pads that we are going to be completing over the next month are spaced on 220-foot laterals. But -- so the first test was the Union. We are happy with those results, and hopefully we see some more results on Kelly Farm and Eberle. Eberle being in the same rock as Phelps, so we know we made really good wells on Phelps with 330-foot spacing. We're down spacing of 220 if we can see some more results to Union with that down spacing, that’s very encouraging.

Welles Fitzpatrick - Johnson Rice

Perfect and that’s 220 in both the Nio and the Codell and is that also the pattern for the majority of that you guys have in here?

Craig Rasmuson

We had better results in the C bench on the Phelps. So two of our three wells that are in the Niobrara, on Eberle are in the C bench, so we alternate C to Codell, B to Codell back to C to a Codell. So, it's really 440 between formation of the Codell and you've got a little more space in that potentially either for infill in the future. But we certainly have infill and rock that's not correct between the Eberle and Phelps, because of the spacing that we could go back to someday. So, it's all part of the science that we're trying to figure our way through.

Welles Fitzpatrick - Johnson Rice

Perfect. That's all I had. Thanks so much.

William Scaff, Jr.

Thanks, Welles.

Operator

And our next question comes from the line of Kim Pacanovsky with Imperial Capital. Please proceed with your question.

Kim Pacanovsky - Imperial Capital

Yeah. Hey good morning or good afternoon everyone. Just a question on Renfroe. I know in your presentation you're saying 10 to 15 month payout and that was down I think from the initial 10 to 18 month and now you're saying less than 13 months. So, what are -- is part of that just due to pricing or what are you seeing in I guess really the last month that made you revise that number?

Ed Holloway

Yeah, both of it is production and pricing, both on oil and natural gas. So, we'll continue to look at that. We're all about cash flow. We're all about payback. To us, we're constantly looking at that and because of pricing; it obviously escalated to a lower payout.

Kim Pacanovsky - Imperial Capital

Okay, great. And also looking back in your operational release that came out a couple of weeks ago, you said you were intrigued by the early results when you looked at sliding sleeve versus plug and perf. Can you just give us a little more color on what you're seeing there?

Ed Holloway

We're -- sliding sleeves versus plug and perf which are seeing some differential, but we don't have enough data that we're going to see more data obviously between adding Eberle and Kelly Farm and the data that we're already creating with Union.

We're seeing more kind of in the design maybe moving the decimal to a higher percentage on production. We're seeing that slick water designs versus a hybrid design which the slick waters are a little cheaper, believe it or not, that we're getting better results on our 30 and 60 days with the slick water.

So obviously 90, 120, 150, 180 days will tell us a lot on those and if the hybrids -- just tracking decline curves and the whole formula of the time that we have and what we're doing with these wells, so we can really model our 15 program and our designs going forward off of this science.

But with just six wells really under our belt with Phelps, we don't have enough data to really make a determination between sliding sleeves and plug and perf. But we do sense that slick water has giving us better production for the first 60 days. We don't sense it. It's hard numbers.

Kim Pacanovsky - Imperial Capital

Okay.

Ed Holloway

It has certainly given us better production than the hybrids are. We'll track those decline curves and truly know going forward what the best formula is going to be.

Kim Pacanovsky - Imperial Capital

Okay. And could you just remind me of the cost difference say on like a 7,000-foot lateral, what the cost difference would be?

Ed Holloway

We're just doing our first 7,000-footer so you I don't have any true data for you.

Kim Pacanovsky - Imperial Capital

Okay. Well let's say 5,000.

Ed Holloway

The standard 4,000, 4,200, 4,300. You can do 26 stages of a slick water for about $1.3 million and a hybrid will be about $1.6 million. So, you've got about $300,000 savings. It's just that simple. You are using a little bit more water, but it's a nominal amount as far as difference in cash.

William Scaff, Jr.

Kim, the real difference between plug and perf and sliding sleeve is the amount of time it takes to frac the lateral. You almost have to add seven to eight extra days for a plug and perf and with a plug and perf, you know exactly where you're putting your fracs, where a sliding sleeve if one of those sleeves gives or two of them gives, you could end up fracking the same spot three different times.

You're just never assured as to where your frac placement may be and then coming back later on, on refracs, definitely plug and perves are more of a better candidate for a refrac than the sliding sleeve. So, that's all -- with that all being said, that's all the differences going forward.

Kim Pacanovsky - Imperial Capital

Okay.

William Scaff, Jr.

And why when you lose time in this business, you just can't make it up.

Kim Pacanovsky - Imperial Capital

Right.

William Scaff, Jr.

And then when we're fracking like in the City of Greeley, we went strictly to sliding sleeves so we could get in and out.

Kim Pacanovsky - Imperial Capital

In and out, right. Yeah. Okay.

William Scaff, Jr.

So, there's a lot of other decision making that goes on just other than that what you want to do.

Kim Pacanovsky - Imperial Capital

Okay. Thanks for that. And then just one last question. It sounds like Nebraska has moved a little bit from watch and wait to possibly being on deck now. Did I detect a change in tone about Nebraska and if so, what's causing that?

William Scaff, Jr.

Yes. There's just more compelling, consistent results. What we're seeing is the success ratio has moved from 40% to 45% to maybe 50%. It's a very intriguing geology area where you have the Cambridge arch (indiscernible) and the D-J Basin and the Kansas City uplift, all kind of intersecting in that Chase, Dundee and Hitchcock Counties of Southwest Nebraska and into Kansas and parts of Colorado. And we are -- yes.

Monty Jennings

Our CapEx budget has some drilling in it for Nebraska.

Kim Pacanovsky - Imperial Capital

Okay.

William Scaff, Jr.

In 2015, to answer your question.

Kim Pacanovsky - Imperial Capital

Okay. More than a couple of wells? I mean, are you -- is there a-- ?

William Scaff, Jr.

Possibly. Possibly. Let's leave it at that for now.

Kim Pacanovsky - Imperial Capital

Okay.

William Scaff, Jr.

Looking it very hard. It is in our CapEx and it possibly could be more than a couple wells.

Kim Pacanovsky - Imperial Capital

Okay, great. Excited to see results there. All right. Thanks a lot, guys.

William Scaff, Jr.

Thanks, Kim.

Operator

And our next question comes from the line of Mike Kelly with Global Hunter. Please proceed with your question.

Michael Kelly - Global Hunter

Hi, guys. Good morning.

Ed Holloway

Hey Mike.

Michael Kelly - Global Hunter

I was hoping to just look into a few assumptions on the 2015 program. I got the capital at 220, 225. Can you give us what you're thinking for number of net wells drilled and completed next year?

And then also just you've got a good kind of ballpark figure for you at the end of the year, what's a good kind of base decline rate on existing production. That would be helpful. Thanks.

Ed Holloway

Well, it depends on how many extended reach we're going to do. It's really a matter of footage, length of laterals, but basically from a starting point, we're probably looking somewhere around 40 gross wells in the 2015 CapEx budget going forward.

Monty Jennings

But you should think of it as a range. That will go -- the pricing that we've plugged in is basically $3.5 million to a little over $4 million depending on what we're doing on the well. So, the number of wells is going to change a little bit.

Michael Kelly - Global Hunter

Got it. And you've historically had a really high working interest. Is that right? What should I model in for average working interest for you?

Monty Jennings

That's going to be at a range too, but I would say 85% would probably be a good--

Ed Holloway

Somewhere between 80% and 90%.

Michael Kelly - Global Hunter

Got it. All right. Thanks. And you know--

Ed Holloway

And we are talking net wells on that 40.

Jon Kruljac

Mike, part of what -- this is John. Part of what we're looking at is swapping acreage and we're looking at these permits right now. Some of it also is dictated by geology in a certain area, so we just haven't formulated what percentage of the wells would be mid and extended reach laterals and what our working interest is going to be on all those yet.

It will be a work in progress, especially over the next couple of quarters. But we do know these next three pads or so, what we're looking at and once we get past Kelly farms, you start gravitating back up to higher working interest pads for the next couple of pads.

Michael Kelly - Global Hunter

Got it. Thanks. I found it pretty encouraging to hear the end of the year; you might have 250 permits that are out there. And I think it kind of begs the question of whether acceleration is in the works regardless of whether we have some setback issues that come to fore here.

Ed Holloway

With the third rig and accelerating the permits, making sure we've positioned ourselves for the next two years no matter what happens, acceleration is in process.

Michael Kelly - Global Hunter

Got it. All right. Thanks a lot, guys.

Operator

And our next question comes from the line of Joseph Reagor with Roth Capital. Please proceed with your question.

Joseph Reagor - Roth Capital Partners

Good morning, guys. Couple of quick questions. First, thinking about the weather issues in the Phelps pad, have those issues been resolved at this point?

Ed Holloway

Yes. We have fixed the casing issue. We're just now trying to schedule frac, when we are going to do that. And I would anticipate that towards the end of August.

The real problem we have is, one is, it’s just one frac. And two is during that period of time, it’s a sliding sleeve. No, it’s a plug and perf. So we will have to shut that pad down for probably 10 days going forward. So we are really trying to find the optimal time at which to do that. But we are ready to go.

Joseph Reagor - Roth Capital Partners

Okay. And then the weather issues involving the flooding? Have those wells been corrected at this point?

William Scaff, Jr.

We have got all, but one pad of directional wells which equates to four total directional wells back-up and running. Some of what was shut in was because of the gas gathering lines were going across the river, the Powder River that flooded and DCP our gas gather shut that in on a safety precaution. Those two pads that were shut in of the 19 wells that were impacted, those were nine of the 19 wells are back up and running. They were not impacted directly. It was just the fact that their gathering system across the river for safety issues were shut in. So we couldn’t produce.

The wells that were directly impacted are back up and running also. We had water on two different pad locations to where our fiberglass production water tanks rose and we had to reset them and we had to refix some earth and berms and things that are required for production in lieu of any event of a spill or something like that may happen. It's just how we construct with the requirements of Colorado.

So those have been remediated. They are back and those wells are back up and running. So the only pad that's waiting right now is still a pad that we're waiting on DCP issue.

Joseph Reagor - Roth Capital Partners

Okay. And then on just real simple on the Wiedeman pad, if you spud in August, you guys are expecting production from that may be in Q2 fiscal 2015?

Ed Holloway

That's the forecast, yes.

Joseph Reagor - Roth Capital Partners

Okay.

William Scaff, Jr.

We wouldn’t get the full quarter by any means.

Ed Holloway

No.

William Scaff, Jr.

Just a matter of how many days we can get in the quarter.

Joseph Reagor - Roth Capital Partners

Okay. And then do you guys have revised guidance number for full year fiscal 2014?

Monty Jennings

No, Joe. We didn’t put that out. We did put out what our exit rate was in June. And what we think our low end of exit rate will be in August. And I think you can kind of look at the numbers between there.

Joseph Reagor - Roth Capital Partners

Yeah, and back it in.

Monty Jennings

Yeah. And those Union pad wells didn’t come on until the end of the month. So we weren’t at 6,500 BOE today at the beginning of June, but we got there once the Union pad has come on.

You got to look at some decline rate going through July into August, but then you have Kelly Farms coming on in August and kind of balances things out. So we are very pleased with where our exit was in June, how things are shaping up in the first part of July here, and Kelly Farms drilling went right according to schedule. We got our frac crew scheduled to come in here third week of July. And so things are really lining up nicely to get Kelly Farms on there.

William Scaff, Jr.

So depending on how Kelly Farms does, that's why we gave a number 6,500 to 9,000 as our exit rate as of August 31. We are optimistic because it’s going to be somewhere in between there or on the upper end.

Joseph Reagor - Roth Capital Partners

Okay.

Ed Holloway

And Kelly Farms, we have like 65% working interest roughly. So just to let you know that. And the other part of that equation is all -- we have a tidal wave of non-ops wells being drilled. It’s just a matter of when they are going to get into production as well. And we had modeled in one and a quarter our net operated -- our non-operated wells to feather through the year and that just didn’t work. And hopefully like we spoke earlier we are going to get some contribution in this fourth quarter.

Joseph Reagor - Roth Capital Partners

Okay. Thanks a lot guys.

William Scaff, Jr.

Thanks, Joe.

Operator

And our next question comes from the line of Jeff Grampp with Northland Capital. Please proceed with your question.

Jeff Grampp - Northland Capital Markets

Morning, guys. Most of my questions have been answered. Just had a couple quick ones. Curious, on the acceleration kind of topic with the third rig, just kind of what are the, may be, check boxes that are remaining for you guys to feel comfortable with getting that third rig full-time after the Wiedeman pad. It sounds like with permitting and things like that becoming less of an issue that maybe that most of those boxes are already checked off? Is that kind of a fair assessment?

Ed Holloway

Yeah, that's a fair assessment. The way that the rig programs have worked, we started off with the first rig, pad-by-pad, went to a contract; we went to a second rig pad-by-pad, went to a long-term contract. Now we're on a third rig pad-by-pad.

We have an excellent relationship with Ensign drilling, and we've fully planned to probably keep that third rig running onto the next pad and the pad after that. So, we'll probably typically happen just like it did on the first two rigs is the third rig will probably turn into a year-long contract once we get into the second pad.

William Scaff, Jr.

And by doing it that way, we really down-size our risk in the event we have a delay of two or three, four weeks. We wouldn't be paying for rig down time. And if we had a collapse in commodity prices, we wouldn't have three rigs on an annual basis or on a two-year basis or a three-year basis where a lot of companies are doing that, but it presents a lot of risk when you have to cut back on your drilling and you still pay for that rig cost.

Ed Holloway

The good news is Ensign allows us to handle it that way whereas other companies say, no you want this rig, you got to take it for a year, because of our long-standing relationship, they said hey, look, you need another one, we know you guys, we know you're going to take it to another level, we're willing to work with you through your process as you continue to grow as a company. So we're very fortunate from that standpoint.

Jeff Grampp - Northland Capital Markets

Definitely a great deal for you guys. And then kind of shifting over to the extension area. Just kind of curious from your guys' perspective, if the Greenhorn and/or Niobrara had turned out as you guys are hoping what is kind of the appetite or ability for you guys to expand your leasehold position out there?

Ed Holloway

Well, we're constantly looking at that area for leasehold expansion. We do have a partner in with us on the majority of that acreage where we are really concentrating is in areas where we can pick up 100% and have 100%, and maybe in the stronger area might not be as well blocked.

What's really good news is the infrastructure's starting to mature out in this area, so it's really easy to identify what areas you can concentrate on. So, we've got the magnifying glass on that and looking at a lot of areas in that extended area.

Jeff Grampp - Northland Capital Markets

Okay. And last one from me would be just curious on the Kelly farms, I noticed that those were all sliding sleeves but most of the other pads you guys have been doing you kind of mixed in plug and perf and sliding sleeve. Just kind of curious why you guys elected to do all sliding sleeve and not mix in any plug and perves there?

Ed Holloway

The real reason is we're right in the middle of the City of Greeley there, the core part of Greeley, and we want to get in and get out and if we went to plug and perf, we'd be fracking for over a month. This way, we should be done, what, Craig, within a week?

Craig Rasmuson

With the slide and sleeves, we can get those jobs done in less than two days each, so we'll be off the location within eight or ten days of rigging and staging up if you will. And like Ed said, we do have -- we've got within 1,000 feet there, we probably would impact hundreds and hundreds and hundreds of people's sleep habits with 24/7 fracking.

The ADR natural gas rigs that we drilled with are extremely quiet and we've got the sound wall that has done a great job for us also, a 30-foot temporary wall that we have constructed from one of the service companies here. We didn't get one complaint during our two months of drilling out there.

I guarantee, the frac is a lot louder than the drilling and we're just trying to be a good neighbor. We've t got other projects coming up in Greeley. We just are trying to be a good neighbor/operator.

And again we kind of talked earlier with I think it was Kim, we're not seeing a whole lot of difference between sliding sleeve and plug and perf just yet on our initial studies on the first five Phelps, but we're in the design of the frac being slick water versus hybrid.

So, we're going to do one hybrid and three slick waters on the Kelly Farms to expand our data so we can keep designing going forward and find that right firm that would make the best wells which we feel like we're getting real close. Every day more data comes in and we feel like we're really getting our hands around how we're going to develop our 15 wells going forward.

William Scaff, Jr.

The community knows that we are making those adjustments and they are very appreciative of that.

Jeff Grampp - Northland Capital Markets

Yeah, definitely. All right. Thanks for the color guys. That’s it for me.

William Scaff, Jr.

Thank you.

Operator

And our next question comes from the line of David Beard with Iberia. Please proceed with your question.

David Beard - Iberia

Good morning gentlemen. I just had some questions about your capital budget for next year. Is that -- or how much AFE is included in there and how much for land acquisitions might be in those numbers?

Monty Jennings

The -- what we plugin right now is 10 million to 15 million for land acquisition and leasing. 160 million, 190 million for drilling AFEs.

David Beard - Iberia

Okay. And I guess that -- if I back in to the number of wells per rig if we use a $4 million well cost that seems to be a fairly conservative wells per rig number given what you've been drilling or am I missing something here in my math?

Monty Jennings

That’s a good midpoint. 40 wells at 4 million a piece is a good midpoint. But as we all know we will modify that as we go through the year depending on the actual well design.

David Beard - Iberia

Okay, okay. My point was really the 40 wells for three rigs, that’s 13, basically -- wells per rigs one a month it just seems a little bit lower than the pace you've been drilling. Is that just to be conservative for all the moves through the pads?

Monty Jennings

Yeah, it is. That’s why we have a range. We brought that third rig on for the Wiedeman pad with eight wells. But as we go -- as we move forward and if we retain that rig than obviously these numbers are going to be on the higher end of the CapEx.

David Beard - Iberia

Got it. And then last question just moving to the balance sheet, when I look at the history of the company, you guys have always carried a decent amount of cash on balance sheet. Obviously, the company has changed pretty dramatically. Is it still of a philosophy you'd like to keep a certain amount of cash on the balance sheet? Or how do you look at that going forward?

Monty Jennings

Well, cash -- cash on the balance sheet is pretty much non-productive asset. So we take it and try to put it in the ground as fast as we can.

William Scaff, Jr.

I mean we try to make sure that we are very liquid so that as we go forward we can make adjustments to decisions quickly. But no, I agree with Monty that as we go forward with this CapEx budget and we are accelerating, that cash is going to be utilized, especially with three rigs running.

David Beard - Iberia

Right, right. Now I understand. Good. Thank you guys and looking forward to the results in the back half of the calendar year.

Monty Jennings

Thank you.

Operator

Thank you. (Operator Instructions) And our next question comes from the line of Chris Morris with GMP Securities. Please proceed with your question.

Unidentified Analyst

Good morning, guys. I'm for on for -- this afternoon.

William Scaff, Jr.

Great.

Unidentified Analyst

Just wanted to get a little bit of color and I had a technical issue earlier in the call, so I apologize if this is a repeat. Just wanted to get some color on what happened with mine pressures during the quarter, both in terms of the impact of the shutdowns of the Eaton and Greeley plant and what you are seeing as weather has warmed up?

William Scaff, Jr.

We are constantly, as we always have and have always stated, battling high line pressure. It did get extreme in the Greeley and the Northern being the Eaton area where our Leffler and Renfroe pads are, for a period of time this past quarter, a period of time that equated to probably just less than two weeks.

Since the line pressures have come back down to a high level, but a reasonable level through the compression that we have on all of our pads. We've experienced the heat of the summer does impact it. But we've experienced that during this shutting time wells tend to load up and you are not producing about the same rate. So swabbing and doing some other operational maintenance things.

It's not just the two-week window where you've got the extreme line pressure. It will take us a good two weeks, which we're just at the end of that two weeks right now of getting these wells lined out and getting them back up to what they were producing prior to the maintenance issues that caused the extreme line pressures that we dealt with.

Ed Holloway

And that’s one of the reasons why we've really scattered our pads around to mitigate any one area if we had high concentration, we had this issue it would be a really uphill battle for us. So in our planning of our drilling pads we are trying to scatter them out so that we don’t have a high concentration in one any general area at this point.

Unidentified Analyst

Great. And just on the LOE, just wanted to know if the flooding or the gas shut -- the gas processing issue had any one-time impact on that for the quarter?

Craig Rasmuson

Yeah, I think it did really have very -- impact on the LOE itself with regards to the flooding side of it. Our LOE increases are mainly because of high line pressure compression and what we have to do on those wells to make sure that these wells are producing at their maximum potential. And in order to do that our LOEs are going to be a little bit higher. But we think they are going to sustain themselves right around the area we're at today.

Ed Holloway

And the new Colorado air emission standards, we have to increase our environmental group that we've hired to overview and oversee that whole program. That has increased some of the LOE cost as well.

William Scaff, Jr.

That’s a substantial cost to an outside third-party. It's not a requirement that we're being very, very proactive to be ahead of what needs to be done in each well site. For inside city limits we have an outside third-party out our every single well site, every 30 days, making sure that we have no emissions that are coming from those wells.

We have purchased FLIR camera ourselves, $100,000 camera to go out there. You scan the camera to see if there is any emissions coming off those wells. And anything that’s outside the city, the third-party environmental firm is overseeing those wells on a 90-day basis. So we are doing these things on a proactive basis to make sure that we are ahead of any requirements and any issues that could possibly come up with the wells themselves.

Unidentified Analyst

Okay. And is the emissions stuff a fixed cost? I mean would it be fair to assume maybe a slight decline once compression is up and running and the emission staff is all in place?

William Scaff, Jr.

We are constantly tweaking exactly what they are going to be do and what are going to be doing and how. We are spending about a $0.5 million a year right now, and, yes, we are going to try to get that cost down on a percent basis per well.

Unidentified Analyst

Thanks a lot. That’s all I got.

Operator

And 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.

William Scaff, Jr.

Good morning.

Joel Musante - Euro Pacific Capital

Yeah, I just had a couple of questions, one on the 9,000 barrel a day exit rate guidance, not to beat this to death or anything. But, I'm just trying to get a sense for if that’s going to be lumpy or it's kind of a flash estimate or how you see that in -- its going to contribute mainly to first quarter I would guess. So, how do you see that going forward?

William Scaff, Jr.

Joel, you are right on that. We are still seeing the lumpiness as we bring these pads on. The 9,000 does assume that both the Kelly Farms and the Eberle pads have come on. As we've talked about that will be late August, perhaps early September. But we do think when that pad comes on we will see another big jump in daily production. And then those wells kind of clean up over the next 30,60, 90 days and then you hit the standard declining curve on them.

Ed Holloway

Nothing has really changed Joel; we are still about 30 days to 45 days behind when we gave guidance originally. We bought on a third rig, that’s not going to count to sub, but in the overall macro picture it takes the company to a level where a year ago we were at 2,000 BOEs per day. Today we are at 6,500.

So we continue to escalate bringing on the third rig. To try to hit guidance in this industry is tough. But, again, we think we are maybe 30 days behind where we were when we gave guidance originally. That really hasn’t changed.

Joel Musante - Euro Pacific Capital

Okay. Fair enough. And then just one more on the -- I'm looking at your working capital and you've got a big cash number but your working capital is close to being neutral. I was just wondering how those -- if there's payables that get paid and how we can model that going forward.

William Scaff, Jr.

No, that's good insight. You're right. And as we start to move into 2015 CapEx, we will be pulling from the bank line. Can't tell you exactly when. But our payables, we push those out as much as we possibly can within industry standards to maximize use of our cash.

So, we literally look at that every day. So, we're watching that very close and again, as we go into 2015, cash flow from operations and cash from our line of credit is going to become critical.

Monty Jennings

As you know, we've benefited over the last pretty long period now of good pricing. So, as long as that holds up, we're very confident in our cash flow from operations.

William Scaff, Jr.

And on the working capital note, the $6 warrants between now and December are definitely going to play a role also in regards to the working capital needs.

Joel Musante - Euro Pacific Capital

Okay. All right. Thanks a lot. I appreciate it.

William Scaff, Jr.

Thanks, Joel.

Operator

And our next question comes from the line of Steve Emerson with Emerson Investment Group. Please proceed with your question. Steve Emerson, your line is live.

Steve Emerson - Emerson Investment Group

First of all, congratulations. I am truly amazed with the progress you've made in a couple of short years.

William Scaff, Jr.

Thanks, Steve.

Ed Holloway

Thank you.

Steve Emerson - Emerson Investment Group

This is more of a technical drilling question. If these ballot measures require much bigger setback from other residences, let's say 1,500, 2,000 feet, can your wells go perpendicular and then turn right to the actual path and how far of an array can it do? I don't know if I'm expressing myself correctly here.

Craig Rasmuson

Steve, you are. This is Craig. We are actually drilling a pad right now where because of the way the field's irrigated and to try to get away from a house, just simply to be a good neighbor, we are drilling from the center of a quarter section going all the way back to the west to get ourselves two of the Western boundary of our leasehold. And then drilling the lateral 4,400 feet across the north half of that lateral, straight east, if you will.

Yes, the rigs, the three rigs we have contracted all have the horsepower to do that. In a perfect world, you'll sit and go vertical if you will and be able to spray out for your mile and-a-half, two mile laterals or even a standard length lateral, but the rigs are capable of drilling more creative locations, if need be, because of a setback and/or in this case it's simply an irrigation issue that we wanted to not disrupt the surface use at the present time and future platting of a subdivision this property's going to be used for in the future.

So, technology is amazing. It's letting us do some neat things. As we stated earlier, those locations that we know that would be impacted by a 1,500 feet or 2,000-foot setback, if it goes to a ballot and if it gets voted in, they all do have waivers where you could get a neighbor to sign and allow you within that 500 feet of today. But we are permitting those locations before the ballot initiative even gets out in November with the of just trying to be ahead of the game so-to-speak.

Ed Holloway

Steve, that example, we really -- it's actually a U-turn, not even a right angle turn. So, to give you -- what's the good news of today is that we have technology that can deal with a portion of that problem on setbacks. If this were to occur four or five years ago it would have been a very huge problem for the whole industry going forward.

So luckily, technology -- the other thing that we had stated -- and I think Bill stated in his remarks is that we have gone out and purchased several of our pad sites. One being a 90-acre farm another one being a 35 acre. So we know we've got some issues. We are going out, finding that real estate and purchasing it.

So, those are some of the things that the company are doing. Pad sites becoming very valuable and the company is blessed with quite a few of them.

Steve Emerson - Emerson Investment Group

That’s excellent. How does it add to cost? Let's say you are having to drill 2,000 feet out of the way and then a typical lateral, 4,000 feet or whatever length it is?

Craig Rasmuson

It's on our turnkey contract. It's built in, but it's very, very, very minimal if we were on a day rate contract. Again, these rigs are prepared to do that. They've going to have to drill that intermediate seven-inch casing section that gets cemented back to the surface. Anyway, it's just a matter of whether you drill it.

If you're going to envision the formation being at 7,000 feet you have to drill 8,500 feet of measured depth or 7,500 feet of measured depth to get you into that right target of the formation for where you want to start your 4.5-inch, where you are going to be fracking that lateral where your legal spacing is allowed.

So it's adding a little bit, and a little bit to the pipe cost that goes in that hole. But as far as drilling it's very, very, very nominal.

Steve Emerson - Emerson Investment Group

Okay. Thank you again.

William Scaff, Jr.

Thanks Steve.

Operator

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

Richard Dearnley - Longport Partners

Good morning. Could you share with us some the results from the couple of Yuma County tests that were going to happen this year?

Ed Holloway

We've drilled one. We really don’t have the exact results back yet. It looks okay. It's nothing that really -- it's not going to move our needle much. We'll have to drill in that area to move in that area. We are going to have to drill hundreds of wells really to go forward. But it’s a commercial well and should have a relatively short payback period, and we're going to give you some more insight on our call. We just really have not focused on that as much as other areas.

Richard Dearnley - Longport Partners

Right.

William Scaff, Jr.

So with natural gas prices increasing we will continue to look at that area as I stated earlier. And it is also involved in our possible CapEx 2015 if natural gas prices reach a certain level, which will close to that today.

Richard Dearnley - Longport Partners

And is that a vertical well or horizontal?

William Scaff, Jr.

Yeah, vertical well.

Ed Holloway

About 22,00 feet in depth you can drill those in little over a day and have them completed in another day. I mean, it's about a one-week process to drilling complete.

Richard Dearnley - Longport Partners

And the -- how much of -- you had about 35,000 acres that -- whose leases were going to expire in '14. Did you manage to either drill most of those and how much of the CapEx budget this year was going towards those acres?

Monty Jennings

There is really very few acres that don’t -- were the leases don’t have provisions for extensions. There is nothing that’s expiring, that’s affecting any of our drilling plans. So we are going to make satisfactory arrangements to get those extended, we think maybe 1,000 is going to go. We may about 1,000 expire. But it's not -- at this point it's not having an impact on us.

Craig Rasmuson

Very, very minimal.

Richard Dearnley - Longport Partners

Yeah, I see. And what does it usually cost to extend acreage?

Ed Holloway

Well, it’s a variety of pricing. But the majority of it that would be expiring is in -- roundabout $100 an acre number. There are some other areas where it -- within in the Wattenberg a much higher than that. But we really don’t anticipate a much of that occurring.

Richard Dearnley - Longport Partners

I see. And the -- has in Nebraska have there been any horizontals drilled over there?

Ed Holloway

Not in the area that…

Richard Dearnley - Longport Partners

…you are.

Ed Holloway

…we are in. There has been a few horizontals drilled in the panhandle part of Nebraska, but none down in this area that we are aware of.

Richard Dearnley - Longport Partners

Right.

Ed Holloway

It’s a very conventional play.

Richard Dearnley - Longport Partners

I see.

William Scaff, Jr.

We get something in there would be on a vertical basis.

Richard Dearnley - Longport Partners

So -- and that would be like Yuma County. It would take…

Ed Holloway

…that's correct.

Richard Dearnley - Longport Partners

…wells to move the needle.

Ed Holloway

That's correct. Well, Nebraska’s oil and it’s about 95% oil and the wells come in 30 to 250 barrels a day. And then they will decline off, but then have a very, very shallow decline curves going forward. So Nebraska has a whole different dynamics to it versus the dry gas.

Richard Dearnley - Longport Partners

Right. It look like from the new map on your website, I didn’t -- the blowup of the four different regions, looked a whole lot blockier than I remember the last map of that nature.

William Scaff, Jr.

When you use collar, it helps.

Ed Holloway

And a small scale.

Richard Dearnley - Longport Partners

Okay. So it hasn’t changed all that much.

Ed Holloway

No.

Richard Dearnley - Longport Partners

Okay.

Ed Holloway

I mean, we are blocking up but nothing that would be significantly…

William Scaff, Jr.

It is our goal. Everywhere we can.

Richard Dearnley - Longport Partners

Yeah. Okay. Thank you.

William Scaff, Jr.

Thank you.

Operator

The next question comes from the line of Irene Haas with Wunderlich Securities. Please proceed with your question.

Ed Holloway

Irene, you are still out there.

Irene Haas - Wunderlich Securities

Yeah, I am still out there. One last question. So to put some sort of deadlines, do you know when is the date where you can change or submit this ballot so we can know sort of in black and white how this is spelled out to get a better handle on it in Colorado.

William Scaff, Jr.

From that -- I am sorry.

Ed Holloway

The ballot initiatives.

William Scaff, Jr.

August 4th. So basically -- is that the question?

Ed Holloway

Yes.

William Scaff, Jr.

I mean, basically they have to get 85,000 signatures. And I think the deadline was August 4th and then whoever it is council or whatever looks at then, said okay. These are valid. You probably need to get 120 to get 85 to make sure they are valid signatures. And then they say exactly which ballot initiatives they're going to approve to actually go to ballot.

Ed Holloway

And currently, first of all, they have got to get state ruling through the courts that they have a valid amendment. And as of within a week I would say, there has only been two that have been cleared through the courts, leaving the other really daunting task of getting that many signatures by August 4. So that's the best that we know at this point. I will tell you that the whole industry is on point on this subject matter.

William Scaff, Jr.

It looks like there was going to be two ballot initiatives, once a setback and one's more of an environmental. That's the best we know today. And I can tell you we go to every meeting we can, give our feedback wherever we can, trying to get involved as much as we can. It’s a day to day battle and it’s going to escalate as we get closer to November.

Irene Haas - Wunderlich Securities

Okay. Great. 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.

Ed Holloway

Thank you, Brenda. Thanks everyone for joining us today and for your interest in Synergy Resources. We believe we can continue to drive shareholder value and corporate growth through the drill bit, organic leasing and bold-on acquisitions, while we remain a low-cost operator with our low G&A and our manageable leverage. We continue to evaluate acquisition candidates. But we will only move forward if we can purchase the right assets at the right price.

Please don’t hesitate to contact us if you have any further questions. Brenda, I can now conclude the conference call and back over to you.

Operator

Thank you. Before we conclude today's presentation, I would like to take a moment to provide important cautions regarding forward-looking statements made during this call within the meaning of the Private Securities Litigation Reform Act of 1995.

These statements are subject to risks and uncertainties and are based on the beliefs and assumptions of management and information currently available to management. The use of words such as believes, expects, anticipates, intends, plans, estimates, should, likely or similar expressions indicate a forward-looking statement.

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

Factors that could cause our actual results to differ materially from those expressed or implied by forward-looking statements include, but are not limited to, the success of the company's exploration and development efforts, the price of oil and gas, the worldwide economic situation, any change in interest rates or inflation, the willingness and ability of third parties to honor their contractual commitments; the company's ability to raise additional capital, as it may be affected by current conditions in the stock market; and competition in the oil and gas industry for risk capital. The company's capital costs, which may be affected by delays or cost overrun; the company's cost of production; environmental 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 July 16, 2014 starting in approximately two hours. Please refer to this morning's press release for dialing instructions. A replay of the audio webcast will also be available via the company's Investor Relations section at www.syrginfo.com.

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

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