Below is the Synergy Resources Corp (NYSE:SYRG) first quarter results for fiscal 2015 ended November 30, 2014. The Company reported its overall financial performance and business operations on Weideman, Geis, Wattenberg, Phelps, Eberle, Codell, Niobrara, and Weld pads. Its revenue is $42.5 million, an increase of 17% from the previous quarter year.
The Synergy Resources Corp (NYSE:SYRG) is a domestic oil and natural gas exploration company whose core operation is based in Denver-Julesburg Basin in Colorado, United States. Based on August 2014 Ryder Scott report, Synergy Resources has 16.3 million barrels of oil and 95.2 cubic feet of natural gas. Its operations span across 308 wells including 39 horizontal wells with an interest ownership in 297 net producing wells.
Company Representatives:
Edward Holloway – President, Co-CEO
William Scaff, Jr. – Co-CEO, Treasurer
Frank (Monty) Jennings – CFO
Craig Rasmuson – COO
Jon Kruljac – VP Capital Markets and IR.
Analysts:
Michael Kelly – Global Hunter Securities
David Beard – IBERIA Capital Partners
Irene Haas – Wunderlich Securities
Ryan Oatman– SunTrust Robinson Humphrey
David Deckelbaum– KeyBanc Capital Markets
Kim Pacanovsky – Imperial Capital
Welles Fitzpatrick – Johnson Rice & Company
Mike Scialla– Stifel, Nicolaus & Company
Joseph Reagor – ROTH Capital Partners
Eli Kantor – Canaccord Genuity
Megan Repine – FBR Capital Markets
David Snow – Energy Equities.
Operator
Good morning everyone, and thank you for joining us to discuss Synergy Resourcesfirst quarter results for the period ended November 30, 2014. With us today are Synergy Resources Co-CEOs Ed Holloway and William Scaff, Jr., CFO Monty Jennings, and COO Craig Rasmuson, VP of Capital Markets and Investor Relations Jon Kruljac will be available to answer your questions during the Q&A session. Following the prepared remarks, we will open the call to your questions. Before the conclusion of today’s call, I will 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 January 23, 2015. The webcast replay will also be available via the company’s website at www.syrginfo.com. I would now return the call over to Co-CEO of Synergy Resources, Mr. William Scaff. Sir, please proceed.
William Scaff, Co-CEO, Treasurer
Thanks, Jessie and thanks everyone for joining us today. We issued a press release this morning announcing our financial results for the first quarter of fiscal 2015. Our financial results for the first quarter are reflection of our disciplined approach towards controlling costs to maximize returns. During the quarter with rapidly declining commodity prices, we will be able to grow our production by 158% year-over-year, while lowering our lease operating expenses in G&A costs per BOE by 15% and 50% respectively. This generated a record 79% EBITDA margin on revenues and for the company and our shareholders during the quarter. We are also focused on lowering our finding and development cost, which our Chief Operating Officer Craig Rasmuson will detail in a moment.
Before I turn the call over to Craig and our CFO Monty Jennings, I would like to state that while we are proud of our 100% plus compounded annual growth rate over the past several years, what is more important to us is remaining good stewards of capital and keeping focused on creating a sustainable platform for the company in all commodity price scenarios.
For those of you on the call that I have had an opportunity to meet in person, you may recall me telling the history about the boom-bust cycles we have experienced over the last 33 years and how we have achieved positive economic results in the past regardless of commodity prices like controlling cost and maintaining a keen eye on expenses.Our Co-CEO Ed Holloway and I personally review each and every invoice no matter how small for our approval. Over the past several months, we have been taking measures to preserve capital and maintain liquidity. This is critical not only to ensure the sustainability of our business model, but also to take advantage of opportunities that might be presented to us during this down cycle.
Some of the measures we have taken include swapping out of non-operated leasehold interest to increase our working interest in our operated assets. This enables us to apply our disciplined cost controls and ultimately result in a higher return on those assets.For example, we recently sold a non-operated working interest to the operator of record rather than commit $54 million to a project, we would more than skeptical could achieve an acceptable rate of return for Synergy and our shareholders.
This decision had a several million dollars of cash to our balance sheet and at the same time, we retained our producing vertical wells on this acreage. In December, we reached out to remaining warrant holders and succeeded in bringing in several million more dollars in cash before year-end with 100% of the warrants exercised. We are also looking at opportunities to monetize some non-core assets.Through these measures and others, we believe we can position Synergy to continue to deliver excellent returns for our shareholders during a difficult period and more importantly set up the company to emerge from this downturn and a stronger position enabling us to take advantage of potentially attractive opportunities.
Thank you. I would now like to turn the call over to our CFO Monty Jennings to take us through the details of the financial results we announced this morning. Monty?
Monty Jennings, CFO
Thanks, Bill and good day to everyone.Turning first to our income statement, I would like to point out that early this morning after we published the press release, we discovered an error in the income statement table attached to the press release. The line for income taxes was inadvertently omitted and we will be filing a current corrected press release later today. The numbers discussed in the body of .
Our revenues totaled $42.5 million in the first quarter of fiscal 2015, an increase of 121% over last year’s first quarter. The year-over-year improvement was due to a 158% increase in production. The increase in production was offset by 14% decrease in our realized average selling price per BOE. During our first fiscal quarter ended November 2014, our average realized sales price was $73.69 per barrel of oil and $4.74 per mcf of gas as compared to $93.06 per barrel of oil and $4.86 per mcf of gas for the first fiscal quarter of 2014.
Overall, the average realized price per BOE decreased to $56.47 compared to $66 a year ago. Commodity prices have continued to decline since the end of the last fiscal quarter and recently the price for oil has traded below $50 per barrel. Price differentials remain higher than what we received one year ago. But, increased pipeline and well capacity has led to a stabilization of differentials at the $9 to $11 per barrel discount to WTI. Our operating income for the quarter increased to $14.8 million from $7.2 million a year ago. Net income increased 247% totaling $21.2 million or $0.27 per basic share and $0.26 per diluted share versus $6.1 million or $0.08 per basic and diluted shares a year ago.
Net income includes an unrealized gain of $16.7 million from commodity price hedges versus an unrealized gain of $2.3 million a year ago and also includes a realized gain on the hedges of $1.4 million compared to our realized loss of $400,000 in the year ago period. Adjusted EBITDA, a non-GAAP term increased to $33.4 million in the first quarter, a 161% increase from the 12.8% million a year ago. Please refer to our more detailed discussion about our use of adjusted EBITDA and its reconciliation to GAAP in the earnings release, which can be found in the news section of our website. We continue our efforts to maintain a low overhead structure. On a BOE basis, we were able to reduce G&A costs by $5.39 per BOE in the first quarter, which is a 50% decrease when compared to costs in the year ago period.
I will now turn briefly to the balance sheet. As of November 30, we have cash and equivalents totaling $47.1 million as compared to $34.8 million at the end of August 2014, our fiscal year end. Since fiscal quarter end, we have had the remaining $6 warrants exercised bringing approximately another $4.6 million in cash to the company. In addition to the commodity derivatives we had in place as of the fiscal year end in August 31, we entered into additional swaps covering a portion of the new production we brought online during the first fiscal quarter. With swaps and collars, we have hedged oil quantities covering 81% of our scheduled future production for December 2015 and 66% of those quantities during calendar year 2016.
Our capital structure remains quite straightforward. There was no high yield debt, preferred or convertible securities burdening the company with high interest or maintenance costs. The current interest rate on our recently amended credit facility remains under 3%. We have approximately $84 million remaining on our $230 million borrowing base to address short-term need should they arise.
Now, I would like to turn the call over to Craig Rasmuson, our Chief Operating Officer, who will provide details of our fiscal 2015 drilling program and the operational aspects of our business. Craig?
Craig Rasmuson, COO
Thanks, Monty. Synergy is in position of great operating flexibility as we have no long-term drilling contracts. Also, our leasehold in the Wattenberg is largely held by production. We feel we can maintain our assets with operating one drilling rig going forward and still reach our goals for fiscal 2015 given the increased operating and drilling efficiencies we have been achieving.
We recently completed drilling our Wiedeman and Geis wells and we have released those two rigs. We currently have one rig drilling, the final well on our Weis pad. That rig will then move to our Cannon pad to spud the first of the 11 wells planned on this pad. We have a 100% working interest in the Cannon wells. Upon finishing drilling the Cannon wells, we will drill 46 operated horizontal wells in the Wattenberg field this fiscal year, which is inline with the revised drilling schedule we discussed in the press release a few weeks ago.
We have been working on reducing cost across our entire operating platform and our preliminary AFE Cannon wells is 3.3 million for standard length laterals with 22 frac stages. We continue to analyze where we can realize cost savings and our goal to reduce [inaudible] well cost of three million or less for the standard length lateral well by the end of the calendar year.
We can complete the 29 wells that we have drilled on the Wiedeman, Geis and Kiehn/Weis pads at our discretion. That discretion will be driven by generating a return on our capital that meets our criteria. Given the current low commodity prices, we are delaying the completion on these wells until later this year and will not be bringing on any new production in the fiscal second quarter ended February 28. This delay will impact our guidance for 2Q by 300 to 500 BOEs a day. That guidance was 8,800 to 9,400 barrels a day.
We are also experiencing severe line pressure and other midstream processing issues in our Northern Wattenberg acreage, which has impacted the production on some of our recently completed horizontal wells including the Kelly Farms and Weld 152 pads. Well, some of these issues can be attributed to extremely cold weather we have experienced over the holidays, most of the impact as a result of capacity constraints. Increased processing capacity is scheduled to be operational by our midstream partner by mid-2015. The exact timing of this expansion in processing capacity will factor into when we complete some of the wells we have already drilled.
On the other hand, we are enjoying a better midstream situation for our wells in the Western and Southern portions of the Wattenberg Field. The 13 wells on the Kiehn/Weis pad and the 11 wells planned on the Cannon pad are in the Western flank of the Wattenberg. The asset we recently acquired is strategically located in the Southern portion of the field or infrastructure and lower line pressures enable more efficient production. We will take these and other factors into account before we begin the next round of well completions. Outside the core of Wattenberg, we are finalizing our plans on the horizontal Greenhorn prospect and expect to spud the initial well in the third quarter of fiscal year. On the Nebraska acreage, our partners are planning to begin activities over the next 30 to 45 days.
I would like to turn the call over now to Ed Holloway, our Co-CEO. Ed?
Ed Holloway, President, Co-CEO
Thank you, Craig and good morning everyone. I would like to conclude the call by highlighting Synergy’s current position and our approach to managing the company going forward. As mentioned during the call, Synergy is in an enviable position of having both operational and financial flexibility and we can choose when or where to spend our capitals. We are not interested in growing production for the sake of production growth if that growth doesn’t create value for our shareholders.
We are in the early phases of our horizontal development of our assets and we can recapture peak production in growth rates rapidly when prudent to do so as most of you know the production profile of these wells in the Wattenberg Field is heavily skewed to the first six to 12 months of production. We are not going to realize that economic return on initial production just to meet production expectations. Rather, we are working diligently to reduce cost, so that as we complete the bulk of the wells in our fiscal 2015 plan, we can bring them on in a scenario that generates an acceptable rate of return for the company and its shareholders.
This is our first raw deal and we successfully managed through several of these privileged downturns. We are highly confident that we prudently manage our assets today. We will be a stronger company coming out of this low commodity price environment in the future. I would now like to return the call over to the operator to conduct the Q&A. Jessie?
Question and Answer Session:
Operator
Thank you. At this time, we will be conducting a question-and-answer session. (Operator Instructions). Thank you. Our first question comes from the line of Mike Kelly with Global Hunter Securities. Please proceed with your question.
Mike Kelly, Global Hunter Securities
Hi, guys. Good morning.
Ed Holloway, President, Co-CEO
Hey, Mike. Good morning.
Mike Kelly, Global Hunter Securities
I was hoping just for a little bit more color and thought around decision to hold back sort of these wells online. What determines when you turn these things on — put them online if there is some sort of threshold there whether its price and how you would layer these engines from a modeling standpoint would be helpful. Thanks.
Ed Holloway, President, Co-CEO
Well, Mike. This is Ed. For one thing, the pricing scenario, we have drilled these wells so about a third of the cost of drilling and completing into the drilling phase. Two-thirds of the cost is in the completion side of things. I feel the earlier stages of negotiating all those costs — I think people are finally falling in line and we have gotten quite a few concessions going forward. I think we will continue to do that. Waiting is not really going to hinder us in our development on that side.
The other thing is the cycles run in a pattern where — in times if you rush your timing, like I said in the call the price production in that first six to 12 months is very critical. They hit a certain threshold and we are modeling that out as we speak. Then the other thing is basically timing of those cost, Mike. We are working with vendors to talk about getting paid with longer credit terms basically making sure that we are holding on to as much working capital as possible. Even if we were to frack these wells right away, it is still going to take as a three months for revenues. We are talking to the very fracking companies about delayed payment schedules, which is what happened in the 1980s and the way we handled it back then and that is the way we are attempting to handle it once again now.
Mike Kelly, Global Hunter Securities
Got it. Appreciate that. Maybe just a follow-up on the cost side. Like December 18, when you guys put up your ops update, you stated $3 million or $3.3 million was going to be go forward cost to give the AFE a $3.3 million on recent pad here. Any change to that, things going out worse here over the last month, so the potential that you will push that lower below $3 million? Thanks.
Craig Rasmuson, COO
Mike, it is Craig. It is in the $3 million to $3.3 with all the contingencies and overhead that we put into our AFE. It is sitting solidly at $3.3 million with nearly $300,000 of contingencies and overhead. We really do credit our staff and the diligence and the relationships that our vendors across the Board have with us and the trust they have in us. They are doing great things as far as bringing down their cost. Great examples of Weld 152 pad – the completions for those wells slick waters were in the $1.2 million to $1.3 million range and all the way to $1.4 million to $1.5 million. Then also the phase of fracks in the Niobrara on that pad was in the $1.7 billion to $1.8 million. That $1.7 million to $1.8 million now is down to about $1.1 million, $1.2 million as far as the bids we have seen, $1.3 million depending upon that.
We are limiting the four stages of fracks that is helping that come down a little bit not necessarily limiting. We certainly feel like we are honing in on the right space with 180/185-feet per stage. The 26 stage fracks that we had been doing versus the 20 stage fracks and 18 stage fracks within the run and left those early on, we really feel like we are honing in as some of our other peers are on that 22 stages 180-feet space.
We are realizing without even the downturn in commodity pricing we were realizing that — we were going to be going in that direction. Things are going well on bringing those costs down and we are excited to go ahead and realize that going forward in the rest of the fiscal years drilling program.
William Scaff, Co-CEO, Treasurer
You are right Mike, the realization setting in more and more with these companies. We had meetings yesterday. We got more meetings today. We’ got meetings all next week with each one of the vendors one on one. We are seeing with each meeting that they are getting a little bit more aggressive on bringing those prices down. Our goal is to realize around $3 million and see where it goes from there.
Mike Kelly, Global Hunter Securities
Great, good color. Good quarter. Thanks guys.
Ed Holloway, President, Co-CEO
Thank you.
Operator
Thank you. Our next question is coming from the line of David Beard with IBERIA. Please proceed with your question.
David Beard, IBERIA
Hi.Good morning, gentlemen. Congratulations on the quarter and thanks for the detail relative to your operations. My question really relates to how long would you keep these wells uncompleted? Is it a function of commodity price? Is it a function of getting the service cost down? The corollary to that is, we still go ahead and drill and sort of build a backlog of uncompleted wells. Thanks.
William Scaff, Co-CEO, Treasurer
Yes. We are going to go ahead and continue to drill on our Cannon pad and the function of bringing these wells on and its takeaway capacity at the midstream level, weather conditions not having to heat tanks, doing some various things. If we are going to wait, let us wait and see as economical as we can possibly be. At the same time watching commodity prices, you get as good as mine. Are they going to settle down here or they are going to go lower?
In the meantime with the weather constraints, the highline pressure, even though some of these wells are more on the western side, we are still going to be very cognizant of all of those working parts before we make a final decision. I will tell you as of today, we are looking at that and we have not made that decision just point in time. With this cold and some of the constraints we are having with the highline pressure, I can tell you it would not be next week. It is going to be some time in the near future as we start to go ahead and bring these pads on one at a time at a time that makes sense.
Craig Rasmuson, COO
David, it is Craig. We will strategically go to those Western flanks out of those 13 wells on the one pad, the 18 wells and the five Weis wells first simply because the line pressure over there is 80 to 100 pounds less than the max that we are seeing in the heart of the Wattenberg has been. The heart of our acreage has been the Greeley area than the Northern flank. DCP Midstream has their Lucerne II Plant coming on. Originally, it was April. We had a tough stretch of cold in November and then really got over the holidays. We just reached out to them earlier this week. According to them, it is looking more like May 30 delayed.
Those impacts are Wiedeman and our Geis pads drastically. We will strategically let that line out and then get ourselves into the system at that point in time because they feel like that is going to be able to draw up pressures to a level where we can go ahead and produce the flash production the way we need to.
Jon Kruljac, VP Capital Markets and IR
David, its Jon. Our intension right now is to complete all 29 wells and Cannon this fiscal year probably staggering it, look for an update from us in the next six to eight weeks. We are still working on some of these cost equations and some other timing issues. Our intension is still to get all these wells online before fiscal year-end. If there is any change from that,we’ll give you that in an update. We will try to give you some more detail on when we were scheduling with our frack spreads these pads on a timely basis. We had originally planned to have one of the pads on production during the last couple of weeks of February and we want to give you a heads up that does not going to happen and we will give you some details what we think we are going to bring on in the third and fourth quarter on a timing basis.
William Scaff, Co-CEO, Treasurer
On the drilling side, yes, we are going to continue to drill with that 11 Cannon wells that we were going to be moving off this Weis pad, moving right over the Cannon and drill those 11 wells.
David Beard, IBERIA
Good, good. That makes a lot of sense to me. Smart decisions. Just if I could sneak in a follow-up on a related topic, what is your view on the acquisition environment and just maybe if you could give us a little color on what is coming in over the transom?
William Scaff, Co-CEO, Treasurer
Well, I think as time continues to move on depending where pricing goes. I think we are going to continue to get more targeted risk and there is going to be a lot of opportunities out there. We are talking, looking and here is where you make companies. We are actually excited about the opportunities that are out there, and we are going to continue to be looking at where those opportunities fit for Synergy.
Jon Kruljac, VP Capital Markets, IR
David, this is Jon. Just a follow-up, as you know in the past from the acquisitions we have made or people in organizations that we have been talking to for months or years before we actually got something done. That continues where we have a variety of discussions that a variety of levels of development and we are starting to see some different posture from people. Right now, for us, it was focused on getting our cost down inline so that if we do make an acquisition, we know what we can develop, at what prices, at what economic return.
David Beard, IBERIA
Well, thank you very much for all the time. I appreciate it.
Operator
Thank you. Our next question is coming from the line of Irene Haas with Wunderlich Securities. Please proceed with your question.
Irene Haas, Wunderlich Securities
Yes. Hey, I just want to be really clear. In mid-December, you talked about the second quarter. You produced about 8,800 to 9,400 barrels a day. What happen to that [inaudible] cut from then, obviously? Then are you still maintaining your fourth quarter exit rate of 13,000 barrels equivalent a day for fiscal 2015?
Ed Holloway, President, Co-CEO
Well, Irene, this is Ed. As Jon mentioned, it all depend on how the 29 plus 11, so that is 40 wells, how those are staggered in. Definitely, that was in the numbers going forward with us. I think our exit rate, if everything goes according to plan with all the wells being completed in this year, then our exit rate could be in that range.
Irene Haas, Wunderlich Securities
That is assuming that commodity prices stabilize somewhat. I mean if they continue to deteriorate, then that could trigger another probably more delay?
Ed Holloway, President, Co-CEO
Yes.
Irene Haas, Wunderlich Securities
Okay.
Ed Holloway, President, Co-CEO
At this point in time, you have to be so careful because you can flush a lot of capital down the toilet. We do not — you just have to really watch where you can position yourselves and get the right economic return for the cost that we are going to have on these wells. We have modeled out. I do not know how many scenarios. It is not 100 but it is pushing them 30 to 40 different scenarios where we need to be and what would press that trigger going forward for us.
Like I said, it is so critical in the first 12 months. We got to get have a comfort level that we can hedge ourselves into our comfort level or we are feeling that the trend is changing and going upward because of the time delay on drilling our pads and completing our pads. This is not an instantaneous event.
Irene Haas, Wunderlich Securities
I understood. One more question. At what point would you guys be comfortable giving us some sort of decline curve that can accurately describe your assets based in the DJ basin?
Jon Kruljac, VP Capital Markets, IR
Irene, we are working on that now. We feel PDC has done a pretty good job of differentiating in different areas. Our footprint is slightly different, but we are working with our reserve engineer here in house. We are probably looking at kind of three different areas. So far on our internal numbers, our wells are with the exception in Lefflerpad but all the other pads are tracking at or above our internal tight curves. We feel comfortable with kind of general numbers we have given you but we would hope here over the next couple of months sometime that will have tighter curve detailed analysis for you.
We finally just have enough time to sampling there that it starts to make some statistical integrity sense that we can come out with that. We really are pleased with our performance. Going back to the other question and Ed brought it up, remember what we said, we are going to be consistent about this. We want our money back. What we are looking at timing of completions we want to make sure, we are going to be getting our money back. We had always looked at whether we are drilling vertically three year payout or better. We are really averaging around 15 to 18 months on our verticals. We did not get to horizontals with that two-year pay out or better.
I think that if we can look forward in a low-price environment and be close to that three-year payback, we’ll start to click these –round of completion going in but stagger them and hope for just some. When you start getting your cost down, if you get just a slight bump in prices, it makes a meaningful impact in that payback period.
Irene Haas, Wunderlich Securities
Okay, great. Thank you.
Operator
Thank you. Our next question is coming from the line of Ryan Oatman with SunTrust. Please proceed with your question.
Ryan Oatman, SunTrust
Hi, good morning.
Ed Holloway, President, Co-CEO
Good morning, Ryan.
Ryan Oatman, SunTrust
Most of my M&A and kind of well cost questions have been answered. You mentioned sort of at the script the operating and G&A cost, which were lower and certainly below my expectations this quarter. Should we look for lifting costs to stay in that kind of $4 barrel range or do you think the workovers, which will basically nail this quarter will kind of bring that back towards $5 barrel?
Craig Rasmuson, COO
It is probably realistically can be somewhere in the middle of that forecast — what we are doing out there and things that are needing attention and work over on it. Obviously, concretion and all that, is it a premium right now with the highline pressures we are experiencing? We feel like we have honed in on that. It is cyclical to when we turn wells on and within six weeks or so we are tubing them up. All of that is cyclical to our completions also. It is a good question. We just, off the cut, right about in the middle of that is probably going to be where we land.
Ryan Oatman, SunTrust
Prefect. That makes sense, then just one quick follow-up on the new well design. I understand you are reducing the frack stage count but increasing the sand volume per stage. What I am unclear on is the net impact. Is that overall amount of sand per lateral foot, is that increasing or decreasing?
Craig Rasmuson, COO
It is increasing. Especially in the Niobrara, we have tracked a lot through the wells that we do have online. Then also wells that were non-operated into that we’ve got the inside information on the completion designs. We really feel getting into that 1,100/1,150 pounds per foot in the Niobrara, maybe even pushing 1,200 or 1,250 on some wells is what we are going to be looking at. The Codell is about staying normal about 900 pounds per foot, and we feel pretty good about the numbers we are making in the Codell.
Ryan Oatman, SunTrust
Great. That is it from me. Thank you.
Operator
Thank you. Our next question is coming from the line of David Deckelbaum with KeyBanc. Please proceed with your question.
David Deckelbaum, KeyBanc
Good morning, guys. Thanks for taking my questions. Just a little bit color on the $3.3 million on the recent AFE, does that also include the benefits already from turnkey versus day rate improvements on the drilling side?
Craig Rasmuson, COO
That is what the day rates. Yes, that’s couple of hundred thousand dollars savings per wells what we are forecasting. We go into day rate from the turnkey.
David Deckelbaum, KeyBanc
Okay.
Monty Jennings, CFO
That does include some vendors coming down in price but not all. We still got some realized savings coming forward, and that is why our goal is to get to $3 million.
David Deckelbaum, KeyBanc
All right. I guess also suggest or complements the idea of deferring some of these completions into a lower service cost environment. The deferred activity, do you still intend on testing the Greenhorn this year or would that be something that gets pushed out into a better commodity environment?
Craig Rasmuson, COO
No. It is on our schedule. It is about timing of rig right now. Whether we take the existing rig we have and/or opportunities for rigs, we get a lot of calls. There is a lot of rig vendors are reaching out and people have set their 15 program and/or firming up their contracts in the 2015 program here this month. Finding a window for whether to bring a second rig in for that single well, bring a second rig in for some other work, too. It is all going to be driven by what happens over the next 60 to 90 days as we forecast through not only pricing the commodity prices.
Monty Jennings, CFO
We are currently moving forward with rig 131 as we talked about on the Cannon. We have the potential to bring 138 back in about 90 days and depending on the timing of where we are at with rig 131 versus where we are at on the Greenhorn. We may use rig 138 to drill that well. It will just all depend on timing.
David Deckelbaum, KeyBanc
Okay, great. Then one more if I might, you had mentioned it is non-core asset sales, did you view non-core asset sales as being something that you would look out just as a source of fund that if you were to pursue other acquisitions? Do you feel like you need to build up some sort of war chest right now preemptively?
William Scaff, Co-CEO, Treasurer
Well, we are just looking for areas where it makes sense to take cash. That if cash if available in the areas that are non-core. I will kind of leave it at that.
David Deckelbaum, KeyBanc
Okay. Fair enough. All right. Thanks a lot, guys.
Operator
Thank you. Our next question is coming from the line of Kim Pacanovsky with Imperial Capital. Please proceed with your question.
Kim Pacanovsky, Imperial Capital
Hey, good morning, everyone. I just wanted to clarify the liquidity. Looks like you ended November 30 with about $200 million of liquidity and that was prior to the $75 million payment for the acquisition leaving you with a $125 million. Is that correct?
Monty Jennings, CFO
I think that the way we look that is we amended our bank credit facility shortly after the end of November. Based on that that amended facility which went into effect on December 15, we did draw down about $66 million to complete that to pay the cash portion of the Bayswater acquisition price. At that point in time, we had $84 million left under the facility. It is $230 million borrowing base.
Jon Kruljac, VP Capital Markets and IR
We are still the cash on the balance sheet, Kim.
Kim Pacanovsky, Imperial Capital
What was that $37 million?
JON KRULJAC, VP Capital Markets and IR
$47 million.
Craig Rasmuson, COO
$47 million at the end of November.
Kim Pacanovsky, Imperial Capital
$47 million, okay, so $47 million. When is the next borrowing base redetermination? How do you think about in this market which is going to get very attractive for asset purchases? How do you think about funding an asset purchase?
Monty Jennings, CFO
The redetermination schedule did not change. We did a semi-annual reserve report. The effective date to those is still the end of February and the end of August, and so that will be the same…
William Scaff, Co-CEO, Treasurer
That typical timing on our redetermination through the borrowing base then would be end of April, early May timeframe with what we’re really looking at that. The reserve report will be done at the end of February, but we got to go through that whole exercise and then go to the bank. It is kind of 60 days at the end of that.
It just depends on what assets come for sale, what price we have been able in the past to have a sizeable junk of our assets purchases include a stock component. That would be one thing that we are looking at. Everybody that has taken stock in the past has been pleased. We have to continue to drive shareholder value. That would be part of the discussion. Some of these situations maybe quite distressed where they do need some cash. We will really be looking at it, but our acquisition focus would be core Wattenberg.
Kim Pacanovsky, Imperial Capital
Okay.
Monty Jennings, CFO
Every acquisition presents its own financing opportunity. The one we just completed — the bank came forward with a very good cost of capital. It is still under 3%. We went that route, but every acquisition part of the discussion is the financing aspect of it.
Jon Kruljac, VP Capital Markets and IR
Even on that acquisition you saw that we were negotiating all the way up to closing. They went from 30% stock to 40% stock.
Kim Pacanovsky, Imperial Capital
Right.
Jon Kruljac, VP Capital Markets and IR
That was something we felt needed to be done based upon how the market had changed. They were more than willing to take our stock as currency. We will continue to look at that going forward what makes sense, what’s accretive and is it a stock or cash.
Kim Pacanovsky, Imperial Capital
Okay. Then just a follow-up on the non-core asset sales, what kind of levels of non-core assets are available to you to actually sell?
William Scaff, Co-CEO, Treasurer
From the standpoint of what we were looking at because tipping our hand is – there are just some various leases or there are various vertical wells that are eventually going to be impacted. There are just other assets that probably do not slate into our plan moving forward.
Kim Pacanovsky, Imperial Capital
Okay.
Monty Jennings, CFO
Again, I would like to just leave it there.
Kim Pacanovsky, Imperial Capital
Okay. That is fine. Thanks a lot guys.
Operator
Thank you. Our next question is coming from the line of Welles Fitzpatrick with Johnson Rice and Company. Please proceed with your question.
Welles Fitzpatrick, Johnson Rice and Company
Hey, good morning.
William Scaff, Co-CEO, Treasurer
Hey, Welles.
Welles Fitzpatrick, Johnson Rice and Company
Can you talk a little bit about how you guys are thinking this completed well cost reductions might be treated in the February redetermination? Is there any difference typically in how Ryder Scott might treat say pricing versus design savings?
Ed Holloway, President, Co-CEO
One thing, it is going to be — what we talk from a Ryder Scott about is getting a really reflective current AFE cost. That is going to be critical across the board. That is a real a real critical factor in the reserve base determination and then the price deck and everything else. It is going to be interesting how they are going to treat these 29 wells, and then most likely none of those will be completed in the quarter. We just have to work that through with them and see what their confidence level is. One thing that we are seeing is that they are feeling more comfortable not with more data basically link the time data and decline curves as you spoke about earlier. They are getting more comfortable in certain areas in the Wattenberg especially, where their confidence level is a lot higher than it was a couple of years ago.
Craig Rasmuson, COO
Yes. Well, the rules are pretty specific for an SEC reserve report. On the pricing, as you know, we use that 12 month to look back. It is just part of the rules. The rules were current costs. When we do our February redetermination, we will be based on what our February actual costs are and then we will go through that. They will be updated from August to February at that point in time.
Welles Fitzpatrick, Johnson Rice and Company
Okay. Perfect. Then if I could just do one — more any update on maybe a 50 or 60 day rate on the mid length Codell, Niobrara wells from the Eberle pad?
Jon Kruljac, VP Capital Markets, IR
Well, we usually do not give out that kind of interim data. We do not have the 60 days. We will have that shortly. Look for something on those in an offset date here in a few weeks.
Welles Fitzpatrick, Johnson Rice and Company
Okay. Perfect. Thanks so much.
Operator
Thank you. Our next question is coming from the line of Mike Scialla with Stifel. Please proceed with your question.
Mike Scialla, Stifel
Hi, good morning guys. If I am hearing you correctly, you probably do not bring on any wells in your fiscal second quarter and just trying to get a sense for how to model production. I assume you are above that 8,300 BOE per day level now. Can you give us any sort of sense as to what second quarter production would look like if you don’t bring on anything? Is it flat sequentially with the first quarter or up or down? Can you point us in that direction there?
Jon Kruljac, VP Capital Markets and IR
Yes, Mike. We had somethings built in there. Clearly the pad that we felt would be on at the end of February is not going to be there, so we are taking that out. I would say flattish is probably about right. We got to look at the non-op and what is happening there, and then look at this decline curve on the acquisition that we made. Production in November was above the internal, but we have not seen the full December production yet from that, so that will have an impact. We will give you some second quarter guidance here in a few weeks before the end of the quarter.
Monty Jennings, CFO
I would assume flat and the acquisition helps to keep that flat based upon whether decline.
Ed Holloway, President, Co-CEO
Yes. We are still impacted on those two pads. If we get any relief there that will help. It has been a real struggle on those two pads, the Kelly Farms and the Weld 152, which are both good producing pads. It’s just that there is just a model back there that needs to be cleared up.
Jon Kruljac, VP Capital Markets and IR
This is also goes to one of the earlier questions on LOE. We were at a point there in those Northern pads, Kelly Farms, and Weld 152 that the line pressures are so high, it does not make sense to be battling it. We are not going to be spending a lot of LOE or as much LOE expenses we had in the past. Without bringing some new pads on, LOE could actually still look good in the second quarter. I think modeling forward, we would [unintelligible – 00:44:36] that 450-ish range on lifting cost.
Mike Scialla, Stifel
Okay. That is very helpful. Appreciate that. Then my other question that sounds like probably it’ is kind of along the lines of the one Welles just asked, so maybe it is coming in an update but as curious on the Kelly Farms. For one, probably you did not get that put into an eight-inch line yet or if you did there are still some constraints on that. Then I was curious as to how those two Codell wells were performing there?
Craig Rasmuson, COO
This is Craig. One we were able to run a big versus the highline pressure. The line pressure there has been the worst we have ever seen. We have not had the eight-inch installed yet. It is just now finally on our docket to go ahead and decide if we want to participate in the cost to go ahead and install that. What we would have asked DCP to do is to model what that eight-inch is going to do for us because it is taken it to the same extreme line pressure. The four inches there it serves and gets to the six, gets to an eight, but eventually gets to the Lucerne plant.
The Lucerne plant is just maxed out right now. That is the bottom line. Even putting the eight-inch in over the last 30 to 45 days, we have realized that there may not be until the Lucerne II turns on in May. There may not be a benefit to pay in capital to go ahead and put that eight-inch at this present time. We are still evaluating that.
Long story short is when they do run they are holding up strong, the pressures are unbelievable. They keep increasing — the longer we are shut in, the less they can produce. We have no concerns there that once we get the alleviated capacity and midstream capacity, those pressures alleviate. We are going to have four stellar wells there.
William Scaff, Co-CEO, Treasurer
One thing I have to add, Mike, too, is this is where the acquisition. The strategic nature of the acquisition has been very important for us because line pressures in the southern part of their field are much more conducive towards a fuller production. We now have optionality to move more of our future drilling operations down into the Southern part of the field along with what we are doing on the Western flank, which is also about 100 pounds less or more sometimes in line pressure.
Mike Scialla, Stifel
That makes sense. I appreciate the color. Thank you.
Operator
Thank you. Our next question is coming from the line of Joseph Reagor with ROTH Capital Partners. Please proceed with your question.
Joseph Reagor, ROTH Capital Partners
Good morning, guys. A lot of what I had been probably touched on already, but just one I guess a bigger picture item is that, the 22 well pads you guys have permitted in the Greeley are sounds like it is kind of in the backburner for now. Would that be the next in the queue following Cannon?
Craig Rasmuson, COO
Originally, it was there.We are still evaluating whether we — one of the things we love about that pad is the fact that it is only half mile from the Eaton plant at DCP. We just need to see when Lucerne II turns on and how that affects the whole basin if you will. Right now, the Western flank and Southern tier, again, where Jon just touched on with the acquisition is where we would go as a plan B versus going to the Eaton pad.
The great thing with the Eaton pad and a lot of other things we are looking at in our Greeley acreage and that Northern flank, Marion, if you will, Novels Greeley Crescent is — that is all of that acreage is HPPd. We do not have any — ours is not on fire to get to any of it. We can time it up as this midstream issue alleviates itself over time.
Joseph Reagor, ROTH Capital Partners
Okay. Then following on that, can you give us an update on how many pads and total wells you have permitted right now excluding the Cannon pad and that 22 Weld pad?
Craig Rasmuson, COO
I have not looked at it in here in the last few weeks. As far as looks and process and/or valid permits — valid permits are a few dozen and what are in process is over 100. In process means within 30 to 60 days of it either getting to the state or being approved by the state.
Joseph Reagor, ROTH Capital Partners
Okay. Then one final thing, it is been kind of out of the news now for a while, but with the Blue River in commission, do you think the lower oil price kind of alleviate a lot of the push for – a lot of the step backs and things of that nature?
Jon Kruljac, VP Capital Markets and IR
No. Probably the political, it is still there. The commission has to give the advisory information at the end of February. We are focused on it. There is a meeting next week where all of our employees are going to go to and justify as being within the industry.
I think from the standpoint, it has cooled off a little bit, yes, but we still have to look to what is going to happen in elections in 2016. We are still very focused. The majors in these areas are still very focused. The commercials of educating the populous are out there more than ever. We are going to continue this time not to ignore just because the heat has come off a little bit.
Joseph Reagor, ROTH Capital Partners
Okay. I guess one more thing if I could. I know it’s been beaten a bit like a dead horse, but on the acquisition side, would you guys look more to use additional debt or to use your equity at this point?
Jon Kruljac, VP Capital Markets and IR
The possibility of both just depends on how — it is very specific to the acquisition on what makes sense, what is accretive. So far, we have been able to use our stock. Its currency is fairly effective and it just depends on the specifics of that acquisition, what they require and how it works between the two companies. Are we afraid to issue equity? If the circumstances are there, no, but it has got to make sense. In this environment that would probably be difficult today.
Joseph Reagor, ROTH Capital Partners
Okay. Thanks guys.
Operator
Thank you. Our next question is coming from the line of Eli Kantor with Canaccord. Please proceed with your question.
Eli Kantor, Canaccord
Hey, good morning guys.
Monty Jennings, COO
How you are doing?
Eli Kantor, Canaccord
Good. Can you remind us what will price stack your banks used in the most recent redetermination and just based on today’s script, any kind of preliminary expectations on where that deck might go in future redetermination?
Monty Jennings, CFO
It is a good question. I do not know exactly which deck they used. I know that they came out at – based on our $530 million PV plus they did give us a credit for the Bayswater assets and they came up with $230 million borrowing base. We had some discussion at that time about the price deck. I do not know what they ended up using.
Yes, we expect that to be a point of discussion, it is always hard to guess what the banks are going to do. I do not expect it to be an issue in the near term but obviously, we keep an eye on it. Over a longer period of time that would be an issue that we have to address.
Eli Kantor, Canaccord
Okay. Fair enough. Thanks guys.
Operator
Thank you. Our next question is coming from the line of Megan Repine with FBR Capital Markets. Please proceed with your question.
Megan Repine, FBR Capital Markets
Hi, guys.
William Scaff, Co-CEO, Treasurer
Hi, Megan, how are you doing?
Megan Repine, FBR Capital Markets
Just my question is really around how should we think about modeling tie-ins of the non-operated wells? Based on your conversations with partners, have you seen a change in posturing the last operations update in December?
Ed Holloway, President, Co-CEO
This is Ed. We have seen a tremendous posturing change from almost all the Operators in the basin. Everybody is very receptive to swapping out interest for interest where they control their head size. Then we increase our working interest in [inaudible]. That dialog is showing on daily with probably six or seven Operators and everybody is pretty much on page there. We are either swapping acreage or swapping – they are working interest on our pads. Again, receiving an increased working interest in our pads and alleviating our non-op side. I think when we came out in our last press release, our CapEx was reduced on the non-op side and we continued to work on that daily. Yes, there has been a tremendous change with the – basically, the larger Operators thinks on the smaller Operators as well. We have been talking continually, and now we are in dialog with everybody.
Megan Repine, FBR Capital Markets
Okay, great. Just following up on that, how material could be asset swapson the amount that you can spend on extended reach laterals beyond the current well backlog that you have here?
Ed Holloway, President, Co-CEO
Well, it is not necessarily driven from extended reach laterals or what not, but it may be conducive for that if we can get the right blocking of acreage and the right geology. There are two factors. You have to have the geology to be able to drill the extended reach lateral, and then you look at the acreage position how you can get there, where to bend. Everybody is looking at that as well. That is going to be keen focus for us on reducing our overhead. [Static sound]I’m getting feedback here. Anyway, we are looking on all that and there is a lot of acreage swapping going on right now.
Jon Kruljac, VP Capital Markets, IR
Megan, our Wiedeman pad, we are looking at swapping out some working interest with another Operator there to increase our working interest above 70%.We have four extended laterals there. Some of the other discussions that we have going on right now, they are really not focused on achieving holistic – 100% working interest for extended reach laterals. It is more increasing more working interest percentages on future pads in general. Some of that impact extended reach and most of it does not.
Megan Repine, FBR Capital Markets
Okay, great. Thank you so much.
Operator
Thank you. Our next question is coming from the line of David Snow with Energy Equities. Please proceed with your question.
David Snow, Energy Equities
Hi. Which is working better – the slick water or the massive sand tracks?
Craig Rasmuson, COO
It depends upon the formation we are in for us. We really feel like we foamed in at the slick water is where we want to be when we are doing a Codell well. The sand really has not very too much on that. It could all be in a center formation as far as height. We feel like the 900 pound is kind of where we want to be per foot.
We are looking at increasing sand in Niobrara just by watching trends from ourselves and other Operators. The rule of thumb, if you are one of the basin, it would be 100 to 150 pounds more in the Niobrara just being that it is a second formation and you hope to connect more rock. We are now seeing trends to 200 feet to 250 feet pounds more, so you are looking at 1,100/1,150. We are just considering ourselves internally that we may even push the envelope on that and look at one or two wells, where we put 1,200 or 1,250 pounds where we have a good thick very porous Niobrara to consider.
So the Niobrara is — when we complete that we like some of the hybrid frack. It is not the slick water with the sand. It is simply value. You trail in. You start with the slick water, but you trail in what a hybrid of the Phaser or something along that line depending upon the completion company we are using.
Jon Kruljac, VP Capital Markets, IR
David, this is Jon. I would just liked to add, we really not cookie cutter on anything. We look at every pad, what’s the geology there, and we have a custom design frack with our service providers for each pad for each formation. We’ll be looking at A, B, and C bench going forward as well as Codell pad by pad with some general rules that we are going to apply. We have always been nimble and a fast follower, so we are watching every body.I would just also to say that we probably would like to get another 50 to 100 wells drilled and have six to 12 months of data to really be replanning it even more. We still need more time. As that said in the script, we are the early stages of our horizontal development. We have even got to 5% of our inventory, so there is still a lot of learning curve to go.
David Snow, Energy Equities
Then the standard length that you mentioned is, what is that, and is it less now, you have tighter spacing and less fracks I think so does that — can you bring me upon what the spacing is?
Craig Rasmuson, COO
Instead of a lateral dispute maybe spaced in either a 320 or 640 acre unit and the 640 being a true square. It is about 4,000 or 4,300-foot lateral depending upon. You have to stop shy of your lease line by 460 feet. You do not frack across the lease line and take someone else’s minerals if you will. That is the state regulated on how we work and run our permit.
The standard length then gives you if you are in the 4,000-foot lateral and you do 180/185-feet spacings of your completions, then you are looking at the 22 stages. That is where we have honed in on that just through simple evaluation of what we have done at the 150-160-feet and what we have done at 200 feet. We think the sweet spot from looking at some non-ops and talking to our brother in the basin is going to be that 180 feet.
David Snow, Energy Equities
I thought in your prepared remarks you said that you were reducing the number of states; I guess I heard that right?
Craig Rasmuson, COO
Well, it is, yes. Most recently we have got 150-foot spacing, so that equates to 26 stages per standard length lateral. We are reducing it down by those four frack stages. We are just not seeing the benefit of the increase in production for the capital we put into those extra four stages,so we are finding that sweet spot.
Jon Kruljac, VP Capital Markets, IR
Again, this will also be dictated by geology in the wellbores with seismic and other offset data. Some of these newer wells might have 20 stages. They might have 24 stages probably swinging around that 22.
Just as a clarification, our first pad Renfroe was 18 stages, 220 feet apart, 225 feet apart in the frack stages .Leffler was 20 stages, and then Phelps and Eberle, Kelly, Weld 152 where in the 25 to 27 stages. They have one anomalous pattern there Union, which was shorter link laterals around 3,200 feet because of lease limitation and geology. We kind of throw that one out of the equation. We had gone down to 150 feet and tightened it up getting 26,/27 stages, while a couple of wells that had 26 and 27 stages outperformed, many didn’t and we are really looking at that 22 stages give or take a stage as the sweet spot.
David Snow, Energy Equities
How much is that saving you in running?
Jon Kruljac, VP Capital Markets, IR
Well, it is going to save 200,000 to 400,000 and we are still refining those savings along with other things because it is not just the frack. It is the other thing that goes along with it. There is a sundry of items. We are zeroing in on that as we mentioned before. Our current AFE on the Cannon wells is $.3.3 million. We have about $300,000 of contingencies there. Our experience in the past has been able to drill lower than the AFE and not utilize all those contingencies, but we are sharpening it up and having a much tighter framework. We are looking at increasing our operational performance across the board. It is just not the drilling time. It is everything that goes along with that, David, so stay tuned.
David Snow, Energy Equities
The slick water adds a $1.2 million, did you say?
Craig Rasmuson, COO
Slick water 22 stages is about $900,000 – to $950,000 completion down from about $1.2 million.
David Snow, Energy Equities
Down, okay. 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, President, Co-CEO
Thank you, Jessie. Thanks everyone for joining us today and for your interest in Synergy Resources. Our entire team remains committed to creating value for all shareholders, so we look forward to sharing our progress in the future. Jessie, you can now conclude the conference call.
Operator
Thank you. Before we conclude today’s presentation, I would like to take a moment to provide important caution regarding forward-looking statements made during this call within the meaning of the Private Securities Litigation Reform Act of 1995.
These statements are subject to risks and uncertainties and are based on the beliefs and assumptions of management and information currently available to management. The use of words such as believes, expects, anticipates, intends, plans, estimates, should, likely or similar expressions indicates a forward-looking statement.
The identification in this presentation of factors that may affect the company’s future performance and the accuracy of forward-looking statements is meant to be illustrative and by no means exhaustive. All forward-looking statements should be evaluated with the understanding of their inherent uncertainty.
Factors that could cause our actual results to differ materially from those expressed or implied by forward-looking statements include, but are not limited to, the success of the company’s exploration and development efforts, the price of oil and gas, the worldwide economic situation, any change in interest rates or inflation, the willingness and ability of third parties to honor their contractual commitments; the company’s ability to raise additional capital as it may be affected by current conditions in the stock market and competition in the oil and gas industry for risk capital; the company’s capital costs, which may be affected by delays or cost overruns; the company’s costs of production; environmental and other regulations, as the same presently exist or may later be amended; the ability to identify, finance, and integrate any future acquisitions; and the volatility of the company’s stock price.
I would like to remind everyone that today’s presentation will be available for replay through January 23, 2015 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 tonight. You may now disconnect.
