Seeking Alpha
We cover over 5K calls/quarter
Profile| Send Message| ()  

Executives

Ed Holloway – President and CEO

Monty Jennings – Principal Financial Officer

Bill Scaff – VP, Secretary and Treasurer

Craig Rasmuson – VP, Operations and Production

Analysts

Irene Haas – Wunderlich Securities

Kim Pacanovsky – MLV & Company

Joel Musante – CK Cooper & Company

Welles Fitzpatrick – Johnson Rice

John Malone – Global Hunter Securities

Jeff Connolly – Brean Capital

Richard Dearnley – Longport Partners

Synergy Resources Corporation (SYRG) F4Q12 Earnings Call November 13, 2012 11:30 AM ET

Operator

Good morning, everyone, and thank you for joining us to discuss Synergy Resources’ fourth quarter and year end results for the period ending August 31, 2012.

With us today are Synergy Resources’ President and CEO, Ed Holloway; the company’s Executive Vice President, William Scaff, Jr.; the company’s Vice President of Operations, Craig Rasmuson; and the CFO, Monty Jennings. Following the remarks, we’ll open the call for questions. Then, before the conclusion of today’s call, I’ll provide the necessary precautions regarding forward-looking statements made by management during this call.

I would like to remind everyone that today’s presentation will be available for telephone replay through December 13, 2012. The webcast replay will be available via the company’s website at www.syrginfo.com.

I would now like to turn the conference over to the President and CEO of Synergy Resources, Mr. Ed Holloway. Please go ahead, sir.

Ed Holloway

Thank you, Ian, and good morning, everyone. Thank you for joining us today. We issued a press release this morning announcing our financial results for our fiscal fourth quarter and year end August 31, 2012. As we reported, the continued execution of our ongoing drilling program in the Wattenberg field of the Denver-Julesburg Basin continues to drive solid year-over-year growth in revenue and adjusted EBITDA.

In fact, in the final quarter of the fiscal year, we achieved nearly a 100% increase in revenue year-over-year to $6.7 million and for the full year revenue up 150% to a record $25 million.

Net income in the fourth quarter increased by 22% year-over-year totaling $1.9 million or $0.04 per share, with net income for the full year totaling $12.1 million or $0.25 per diluted share.

Our fourth quarter performance reflected 120% increase in our oil and natural gas production year-over-year to 116,818 BOEs, while annually it was up 155% to 420,534 BOEs. This equates to an average of 1,270 BOEs per day during the quarter and 1,149 BOEs per day for the full year.

As operator, we drilled 51 wells during the year and brought 16 into production during the fourth quarter. We are currently completing 10 wells that will go into production during the first quarter of 2013. This increased the total number of gross wells to 209. We operate 156 gross wells and have participated in 53 non-op wells.

Our drilling, completion and production activity has led to an increase in our estimated proved reserves to 5.1 million barrels of oil and 33.4 billion cubic feet of gas as of August 31, 2012. The estimated present value of these reserves before taxes and discounted 10% is $149 million, up 140% year-over-year and 43% since we updated our reserve forward at mid-fiscal year.

Now I’d like to turn the call over to our CFO, Monty Jennings to take us through the details of our financial results. After Monty’s results, Bill Scaff and I will provide some additional operational highlights. Then finally, we will open up the calls to your questions. Monty?

Monty Jennings

Thank you, Ed, and good morning, everyone. Thanks for joining us today. As Ed mentioned, our revenues totaled $6.7 million in the fourth quarter of 2012. This represented a 99% increase from the same year-ago quarter. On a sequential quarter basis, fourth quarter revenues declined 10% from the third quarter.

Full year 2012 revenue totaled a record $25 million, up 150%. The sequential revenue decline in the fourth quarter was largely due to commodity price decreases and high line pressure we’ve been experiencing in the Wattenberg field that inhibited our ability to produce at full capacity. In fiscal Q4 2012, our average sale prices were $82.89 per barrel of oil and $2.82 per Mcf of gas as compared to $91.21 for oil and $3.62 for gas in the 2012 third quarter.

The year-over-year growth was driven by substantial improvements in our production. Fourth quarter 2012 production grew 120% over fourth quarter 2011, while full year 2012 production grew 151% over 2011. This increase was primarily attributed to new wells that have come online. We brought 52 wells online during the year and 16 of them late in the fourth quarter. Average annual sales price per BOE did not change significantly from year 2011 to year 2012.

Our operating income in the fourth quarter increased 117% to $3.4 million from the fourth quarter 2011. Net income in the fourth quarter increased by 22%, totaling $1.9 million as compared to $1.6 million in the same year-ago quarter. For both periods, earnings were $0.04 per diluted share.

For the full fiscal year, operating income increased 317% to a record $11.8 million and net income was a record $12.1 million or $0.25 per diluted share. Fiscal year 2011 was a loss of $11.6 million or $0.45 per basic and diluted share, and the loss was primarily due to $14.4 million non-cash charges related to our $18 million convertible debt offering.

With regard to income taxes, none of the reported tax items in the fourth quarter or the full year, either the tax benefit or the tax expense, represent current taxes payable. All of our taxes are deferred into future periods as we have a $33 million net operating loss carry-forward for tax purposes, which will allow us to defer income tax payments into the future.

Adjusted EBITDA in the fourth quarter increased 105% over the year-ago quarter to $5 million, or 74% of sales. Adjusted EBITDA for the full year increased 190% to $18.2 million, or 73% of sales. Please refer to our more detailed discussion about our use of adjusted EBITDA, a non-GAAP term, and its reconciliation to GAAP in our earnings release which can be found in the News section of our website.

We were able to grow our business during the quarter and fiscal year, yet remain committed to managing our costs. Our operating expenses, particularly G&A grew at rates below that of our revenues as we continue to manage the business to maximize cash flow from operations.

Now, briefly turning to the balance sheet. We have deployed a portion of the funds we raised in December of 2011, and as of August 31, 2012, we had cash and equivalents in the bank of $19.3 million, as compared to $9.5 million at August 31, 2011.

Subsequent to the end of our fiscal year, we announced an amendment to our revolving line of credit agreement with Community Banks of Colorado which increased the commitment of the line from $20 million to $30 million. The maximum interest rate on the revolving line of credit is LIBOR plus 3%.

Between our cash generators from operations, remaining proceeds from our December equity offering and borrowings available under our $30 million revolving line of credit, we remain well-capitalized heading into our fiscal year 2013.

Now, in terms of the operational aspects of this program, for more details about our outlook, I’d like to turn the call over to Bill Scaff, our Executive Vice President. Bill?

Bill Scaff

Thank you, Monty. Looking back over our drilling program, which began on August 31, 2011, we have drilled 51 wells during the last 12 months of which 41 of the wells reached productive status by the end of the fiscal year. We expect the balance of 10 wells to reach productive status during our current fiscal first quarter.

We were able to hit all targets and objectives with our vertical and non-operated horizontal drilling programs during the year. We experienced 100% success in our vertical drilling program, participated in our first five Niobrara horizontal wells as a non-operator and have been noticed on 11 additional Niobrara horizontal wells and one Codell horizontal well.

We remain focused on drilling our core Wattenberg acreage in 2013 and anticipate we will drill an incremental 33 vertical wells in the core of this field during the fiscal year. We continue to listen and learn as it relates to our new non-operated horizontal drilling program. We expect to participate in 17 total horizontal wells of which five were drilled during the year and two during the fourth quarter. Horizontal production data available to-date has been encouraging and we plan to begin drilling four horizontal wells for our own account in the second half of fiscal 2013.

We are purposefully delaying the start of our own operated program by approximately a quarter until the new midstream processing capacity comes online early this summer. Looking into fiscal 2013, we expect to increase our previously stated capital expenditure budget of $55 million to $82 million. The increased budget includes the acquisition of Orr Energy assets consisting of 36 producing properties, 2,200 Wattenberg acres and 1,000 acres located in the extended mineral fairway of the D-J Basin.

The purchase price of $42 million is payable with $30 million in cash and $12 million in common stock. We plan to spend approximately $15 million to drill 25 vertical wells and approximately $17 million to drill four horizontal wells in the third and fourth quarter of our fiscal year. In addition, $14 million has been estimated as our portion of the cost of vertical and horizontal wells in which we will participate as a non-operator.

We also planned re-completion approximating $1 million and anticipate that we will spend approximately $5 million of the 2013 CapEx budget to acquire undeveloped acreage. In 2013, we are planning to fund our capital expenditures from cash balances, cash flow from operations, as well as our bank borrowing capacity. So as Monty noted, we remain well-positioned financially with options on our balance sheet to continue to grow the business in 2013.

With that, I’ll turn it back to Ed.

Ed Holloway

Thanks, Bill. Fiscal year 2012 was a strong year for Synergy Resources. As we completed our drilling plan on budget and on time, overall production grew at triple-digit year-over-year driving revenue growth. Our focus on cost control yielded strong EBITDA margins. We have tremendous upside potential from our non-core Wattenberg acreage. Given our long term advantage in this non-core acreage, we are in position to let others prove up our leasehold. We believe that this could be a great risk-reward situation for our current and future stockholders.

Now with that, I’d like to open up the call to your questions. Operator, Ian?

Question-and-Answer Session

Operator

Thank you. We will now begin the question-and-answer session. (Operator Instructions) Our first question is from the line of Irene Haas with Wunderlich Securities. Please go ahead.

Irene Haas – Wunderlich Securities

Yeah. Hi. Congratulations on a really good quarter. And my question is with fiscal 2013, even with sort of the line pressure issue in the background there, should we expect you guys to grow at your historic rate of roughly 20% per quarter in terms of volume?

Ed Holloway

This is Ed. We are anticipating growing at that rate. What we – really our strategy this year, knowing that we had this high line pressure issue that still persisted a little bit into the first quarter, at least through the first two months and then subsided considerably into November, was that we were going to accelerate our drilling vertically early on so that we could get these wells on and producing in middle months of the winter when we believe line pressures are going to come down dramatically, getting that flush production in the months of November, December, January, February, March and April. Then hoping that as our word from the field that DCP is ahead of schedule, or at least on schedule to bring on their first new plant that we will not have too much of a high line pressure issue, or more of a moderate line pressure issue.

We’ve also on our well pads put on a different type of equipment that can handle this high line pressure in a more efficient way going forward. And I’d like to mention that you brought that up, Irene, that in the fourth quarter, we brought on 16 wells, but of the 144 days, that those 16 could have produced, the 1,440 days, we only got in 211 days of production. So I think that our results for the fourth quarter are a lot stronger than one would assume looking at the number of wells we brought on. We definitely had issues with our Greeley Country Club and Aims College where with it being in the city limits, we had to babysit those wells and really be careful on how we tried to flow those wells back, because those are some of the strongest wells I’ve been associated with in over 30 years in the D-J Basin or the Wattenberg field.

Bill Scaff

Craig, do you want to talk – this is Bill. Do you want to talk a little bit about how many wells we actually have brought on since the end of the fourth quarter? And what’s actually in the queue for production going forward?

Ed Holloway

This is Craig Rasmuson, our Operations Manager.

Craig Rasmuson

Yeah. The 16 wells we brought on late fourth quarter, 15 days worth on the Margil 7 pad and we brought on the Aims/Greeley Country Club wells in late July. With what Ed was referring to earlier, the strength of those wells and just the head gas we’re getting from those Virgin wells under the city limits, we’ve had to minimize the number of wells we’re producing on a daily basis. We’re only producing two or three a day of a 9-well pad. So, as those wells line out and we get that head gas off, that will subside and we’ll be able to produce 50%, 60%, 70%, all the way up to 100% of those wells once they’re lined out. It’s just taking some time with the strength of the wells.

Since then, we’ve brought on eight Coyle wells and we are bringing on here within the next week, five Olson wells. And shortly after that in mid-December, we’ll be bringing on six Avex wells. And shortly after that, we have another 16 wells in two more Avex pads and a Pratt pad that will all be in that same neighborhood, and they’re drilled right now, all but six of those 16 are drilled and we’re in process of constructing the production equipment and getting gas line from DCP hooked up and completing those wells. So, by the end of second quarter, we’ll be bringing on a large number of wells.

Irene Haas – Wunderlich Securities

And a little follow-up question, lease operating cost was a little high during the quarter. And what should we look at for 2013? Should it come down?

Craig Rasmuson

Some of those pads, they will go ahead and stay to the average of the higher. That’s added compression. We have – all of our new drilling forward since the Aims/Greeley Country Club, so all the production we’ve brought on since end of July. We’ve invested in a more state-of-the-art separator. The old standard 300-pound separator was not efficient any more.

So, on a number of our most recent pads prior to that, that had the old standard 300-pound separators that everyone in the basin was utilizing prior to the extreme line pressures we experienced this past summer, we’ve added compression to those six most recent pads. And that’s the added operating cost there. Going forward, on our new drills and new production that won’t be the added operating cost with the fact that we’re adding these high-low separators that will push up to 450 pounds into the higher line pressure. So we’re taking care of that with production equipment versus a monthly compression cost to us to produce.

Ed Holloway

Yeah. Irene, this is Ed. As the takeaway capacity improves, our operating costs are definitely going to go down. These compressors that we put on our last six pads are rented on a monthly basis. So once we can start removing that compression off those pads, then the LOE costs will definitely come down. But I think we will have a little bit higher LOE cost through 2013 until that takeaway capacity is resolved going forward. But there’s still very low LOE costs on general.

Irene Haas – Wunderlich Securities

Great. Thank you.

Operator

Thank you. Our next question is from the line of Kim Pacanovsky with MLV & Company. Please go ahead.

Kim Pacanovsky – MLV & Company

Hi. Good morning, everybody.

Monty Jennings

Good morning.

Ed Holloway

Good morning.

Kim Pacanovsky – MLV & Company

I noted in your release that you used the word potential when you spoke about the acquisition of Orr Energy. Is there any risk of that acquisition not going through?

Ed Holloway

Well, there’s always a risk that has that potential. We’re under a purchase sales agreement. Everything’s going very smoothly to this point. We will have the final part of our due diligence done this week, which will determine if there are any other deductions going forward. We’re not anticipating any problems. But it has not closed and it’s scheduled to close November 30.

Kim Pacanovsky – MLV & Company

Okay, great. And could you just talk about realized gas prices? I guess they were lower than we had anticipated. And at what point would you start to – where would your production need to be and what kind of confidence in your production would you need to have with the takeaway for you to start layering in hedges?

Monty Jennings

We’re going to start layering in hedges over the course of the next couple of weeks. It’s part of our bank requirement, and it’s something we’ve been looking to do. With regards to gas prices, we recently had a study done by EKS&H, and under our stress test, gas can go to zero and we would still be profitable, very profitable. But, we also would start moving in hedges on the oil side over the course of the next couple of weeks.

Ed Holloway

Yeah, our revenue mix is so skewed toward oil at the moment that the impact of oil commodity price changes is much greater than that in the past.

Kim Pacanovsky – MLV & Company

Okay. And then looking at the Aims pad, you said you’re only producing two to three wells at a time every day and what is the production coming out of that pad now? And what would it be if the whole pad was on full production?

Craig Rasmuson

To-date, we’re averaging 250 to 300 BOE a day, with two to three wells producing. We’ve recently put on a vapor recovery. Again, our issue there is so much head gas with the strength of these wells until we get that head gas off, that gas is getting to our tanks and you have to produce at a slower rate. Manage that oil coming to your tank. So, long story short, we added just recently in the last 10 working days, a vapor recovery system. We’re now up to four and five wells a day. We feel with flush production, we’re going to be in the 700 to 800 BOE a day, maybe conservatively on that pad. And then obviously beyond that same decline curve once these wells are lined out.

Kim Pacanovsky – MLV & Company

Okay.

Ed Holloway

The other interesting thing is, Kim, that this vapor recovery, and basically what it does is when we produce these wells, the wells come on so strong that they pressure up the holding tanks for oil. And in Colorado we have vapor recovery incinerators that burn off that vapor off the tanks. So in order to get that pressure built up out of the tanks and subside, we put this vapor recovery, which actually injects that vapor back into the sales line or the gas line and I think it’s producing, what, 150 Mcf?

Craig Rasmuson

Or more a day, just with two and three wells going a day, we were up between 150 and 180 added Mcf a day. And obviously as we add more wells, that Mcf increases too. But again, this is a near term problem in the fact that once these wells are lined out and that head pressure is off, we’ll be able to manage them and produce them on time and the end pressure is to where hopefully we get maximized and get nine wells produced a day here within the next quarter.

Kim Pacanovsky – MLV & Company

Okay. So with those wells coming back on with the well head compression on the new pads, can you point to any sort of exit rate or average production for the first quarter?

Ed Holloway

Well, I think the first, we still had a high line pressure going into September and October subsiding in November. Aims Community College wells are coming on very strong now into November. So, I think the story really is not going to be what our exit rate is in our first quarter, which will be up over our fourth quarter.

But it’s going to be what the production rate in the second quarter is going to be because when we really look at what Craig just brought on, really the 16 wells we brought on in the very last part of the fourth quarter are coming on more towards end of the first quarter and we have another 35 wells coming on in the second quarter. That brings a total of 51 wells really coming on strong into that second quarter. So our story is really going to be a second quarter hopefully, a non-line restriction, high line pressure issue. And I think we’re going to have a very, very strong second quarter and a solid first quarter.

Kim Pacanovsky – MLV & Company

Okay. Yeah. Okay, great. I do understand the bump up in the second quarter. But we still have to model the first quarter.

Ed Holloway

Well, I understand that and we’re tipping you off, but we also brought on six non-ops with Encana in the first quarter and then the two Bill Barrett horizontal wells came on in the first quarter of this year. We’re anticipating those all falling in our fourth quarter. So, it is just so hard to predict when you have DCP and Anadarko upgrading their system, really hard to predict when you’re going to be able to get online and produce at the capability that you can produce at.

Kim Pacanovsky – MLV & Company

Yeah. And just looking at line pressure drops during the winter historically, I mean, can you even hazard a gas at how much the pressure would drop and how kind of safe you are even if the new capacity is not there?

Ed Holloway

Okay. All I can give you is my 30-year history in the Wattenberg and I will tell you, in my 30 years in the Wattenberg when line pressure got over 220 pounds, it was described as high line pressure. We got up to, on line pressure, got all the way up to 340 pounds in the fourth quarter. It has now subsided to the mid-200s, and we’re hoping it’ll get down to maybe around the 200 level. Generally, adequate line pressure is 160 to 190.

And then 190 to 220 you can deal with, but once you start getting over that, then the equipment that you have on location and the pressure tolerance that the system has comes into play as well. But, we’re lucky that we’re in the Wattenberg, and we’re very blessed that DCP, a very strong financial company that’s Duke Conoco Phillips and Anadarko. The posse’s been on its way for over a year now, and every update we get from them is that they’re ahead of schedule. And I can tell you they are working like you cannot believe to improve the system and add additional capacity.

Kim Pacanovsky – MLV & Company

Okay. And do they have an actual target date for the first tranche of capacity?

Ed Holloway

Yes, July of 2013, they’ll bring on their LaSalle plant. And we keep hearing that they’re ahead of schedule. So we’ll see what happens.

Kim Pacanovsky – MLV & Company

Okay. Sorry, you did say that. I apologize. All right. Thanks a lot, guys.

Ed Holloway

Yeah, thanks, Kim.

Operator

Thank you. Our next question is from the line of Joel Musante with CK Cooper & Company. Please go ahead.

Joel Musante – CK Cooper & Company

Hi. Most of my questions have already been answered. But I did have one left. You talked in the press release about possibly deferring some horizontal wells a few months until the line-pressure issues are resolved. Some of the other producers in the basin are talking about drilling more horizontal wells and deferring vertical wells. I was just wondering what your rationale was for that?

Ed Holloway

Well, our rationale is; one, that we’re still a very, very small company, and that when we model out verticals versus horizontals, which we like to model out from our own experiences in the cross-section of horizontal wells we have now, that the worst thing we could do is deploy a lot of capital and have restrictions in our ability to produce them. The other thing that we’re concerned about is, we just don’t know how well these horizontal wells will perform if they get shut-in, and what problems that may cause.

As you know, we’re a cash flow driven company and so we’re very concerned that our cash flow continues to drive forward and go for it. So on a – we think we have a very good opportunity because we’re going to be one of the few companies still drilling some vertical wells and we’ll be able to pick and choose when and where and how. There will not be a tremendous amount of pressure of participating with the bigger boys, which we don’t prefer to do. So we look at it as an opportunity going forward and like I said, we still are a very small company, and horizontal drilling takes a lot of capital and we’re just working our way to getting to the point where we can be maybe 80% horizontal, 20% vertical somewhere in the future.

Joel Musante – CK Cooper & Company

Okay. Well...

Bill Scaff

On top of that, Joel, things continue to get more and more efficient. Costs continue to come down. And so, as we position ourselves into the third and fourth quarter, with all this revenue of 51 wells coming online, it just puts us in a much better position time-wise, technologically-wise. And then moving into the third and fourth quarter when the LaSalle plant is supposed to come on, it reduces our risk of being able to produce those wells. They cost $4 million apiece.

Joel Musante – CK Cooper & Company

All right. Well, that makes a lot of sense. That’s all I had. Thanks.

Operator

Thank you. Our next question is from the line of Welles Fitzpatrick with Johnson Rice. Please go ahead.

Welles Fitzpatrick – Johnson Rice

Good morning.

Ed Holloway

Good morning, Welles.

Welles Fitzpatrick – Johnson Rice

On the CapEx, ex the Orr acquisition, it looks like you went from 55 wells to 52 wells and from a well count, or projected well count I should say 51 wells to 47 wells. Is that reduction – obviously, it’s not coming from the horizontal. Is that coming from the operated or the non-op verticals?

Ed Holloway

I’m not certain of the question. But the reduction really comes in our first CapEx that we had $8 million set aside for leasehold and property acquisition. So we just transferred $3 million over into the Orr side of the equation, really did not reduce any of our well count. That’s a guess anyway because we’re guessing on our non-op. We’ve already stated we’re going to drill 25 verticals. We’re going to end up drilling 26 wells, 27 wells, or 28 wells because of the other opportunities coming forward. So that’s a little bit of a moving target, but that’s where all that came from.

Welles Fitzpatrick – Johnson Rice

Okay, perfect. And on those, I think you guys said that you guys have received indication on 17 horizontals, any of those Codells or portions of the down spacing pad, aside from the Anadarko one you guys previously talked about?

Ed Holloway

No. I think we mentioned that we’ve been noticed on 17; 16 of those have been drilled, five are in production. We have – one of those horizontals is in the extended area, very small interest in with Noble. Our sixth horizontal is with Noble and it is a Codell horizontal. The other thing that we’re noticing is – and we have two PDC horizontals that are Codells.

I was just notified of that now. And the thing that we’re noticing is we’re getting a variety of what we call mini-extended reaches, 6,500 laterals, and the vast majority are still in the 4,000 laterals to 4,500 laterals. But we have not seen any down spacing at this point in time going forward. For the A and C bench we haven’t had any of that AFE either.

Welles Fitzpatrick – Johnson Rice

Are those 6,500 footers, are those exclusively Noble?

Ed Holloway

Yeah.

Welles Fitzpatrick – Johnson Rice

Okay.

Ed Holloway

They are.

Welles Fitzpatrick – Johnson Rice

And then, one last one. On the mix, and obviously this is the balls in the air. But on those four horizontals for 2013, what do you guys think in Codell versus Niobrara? Has any of this third-party success – and to be fair, I know you guys have been excited about the Codell horizontally before most. But has any of that success shifted yours thinking more towards the Codell versus the Niobrara for those four?

Ed Holloway

We are still really looking at that as to which way we want to do it and primarily it will be when we drill off a pad, do we want to drill two Niobrara horizontals or do we want to drill a Niobrara Codell horizontal off of that pad? We have not made that decision at this point, but we are looking at it. It definitely is the way everybody is looking at it now, is how many wells and how many formations can you drill off a one pad?

Bill Scaff

But at this point in time, our first four would probably be “B” bench Niobrara.

Ed Holloway

Yes, at this point.

Welles Fitzpatrick – Johnson Rice

Okay.

Bill Scaff

But we are excited about the Codell.

Welles Fitzpatrick – Johnson Rice

And one last one, if I can sneak it in. Can you remind me – can the Ensign 226, can that go horizontally? Or will you have to get the 136 back for that program in the back half?

Craig Rasmuson

Yeah, 226 does not have the horse power to go horizontally, 136 and talking with Ensign, there’s two or three other rigs that are kind of floating amongst operators that are not locked on a year’s contract. So we’ll be looking at that. Rig 55 is a rig we’ve used in the past. That also is a floating rig if you will. So it’ll probably be one of those that they are kind of earmarking for the rigs that are not full under a year contract with an Anadarko or a Noble or alike.

Ed Holloway

Yeah. And I’d like to make, that’s a very good point because one of the things that has really limited us from even thinking about drilling our own horizontals was that, up till just recently you basically had a contract for a full year horizontal rig. Ensign has notified us earlier this summer that they were going to bring on two rigs sometime in late October, early November.

I’m not certain if that has been accomplished yet, that would meet the needs of some of the smaller operators that are going to drill less than a full year’s worth of horizontal wells. And the real problem is with that is that on a year’s basis two years ago, you had a contract for a one rig for a year, you’re probably only drilling 10 wells maybe 11 wells but today in the efficiencies that they’re drilling these wells, you’re drilling 50 to almost 52 – no not 52, about 42 horizontal wells in a year. So that is a major change in what the technology is going about in the horizontal, in the Wattenberg.

Bill Scaff

And on top of that, Welles, 18 months ago when we met with Ensign, it was about $1.8 million to drill, $1.6 million, $1.8 million just on the drilling side. Today, 18 months later, it’s about $700,000 and they’re willing to turnkey it, so again, getting more and more efficient.

Welles Fitzpatrick – Johnson Rice

Perfect. And presumably all of those rigs have been out there drilling horizontally and you get a hot experienced crew?

Ed Holloway

Absolutely.

Welles Fitzpatrick – Johnson Rice

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

Ed Holloway

Thanks, Welles.

Operator

Thank you. Our next question is from the line of John Malone with Global Hunter Securities. Please go ahead.

John Malone – Global Hunter Securities

Yeah. Good morning, guys. So far doing my math it looks like you’ve got $27 million in overhead on a revolver. You talk about in the release anticipating funding the program with cash, cash flow, and additional borrowing. Can you see any more capital draw, more debt draw beyond that $27 million in overhead going maybe a year and is there any contingency you’ve set up if you have to?

Ed Holloway

I can answer that. That the $30 million was based off our mid-year reserve report and we are currently in discussions with the bank on putting together a much larger reserve base drawing facility. And we feel fairly confident that, that should take place within the relatively near future.

Monty Jennings

But, again, John, with our current cache of 51 wells coming on line over the course of the next 30 days to 60 days, and our bank borrowings, we feel that we can accomplish what our CapEx is, including the acquisition through the end of the fiscal year.

John Malone – Global Hunter Securities

Okay. That’s it for me. Thanks.

Operator

Thank you. And our next question is from the line of Jeffrey Connolly with Brean Capital. Please go ahead.

Jeff Connolly – Brean Capital

Good morning, guys.

Ed Holloway

Good morning.

Jeff Connolly – Brean Capital

Can you just remind us how the spacing on the City wells impacts your proved reserves, as far as booking them?

Ed Holloway

Yes. We have a considerable leasehold within the City of Greeley and some other municipalities. And with SEC requirements that you can only go out one spacing unit from a producing well in any direction, and book that as a PUD. Our leasehold within the City of Greeley especially, is in the core of the Wattenberg. These nine wells that we just drilled really shows what Virgin Codell, Niobrara production, it just – it has really set us back, as we have not seen these type of wells in a long, long period of time.

But unfortunately, having our leasehold in the city limits, there aren’t any wells surrounding that leasehold. So as we drill, we are creating our own PUD value, but we still cannot get out beyond the 20-acre spacing where we have additional wells to go forward. So, on a private basis, you could book every acre you had in the City of Greeley, but under SEC, they limit you tremendously. Even though you’re in a very large, well-defined field, it’s just one of the semi-frustrating points of being a public company. But we’re very happy with our results. We’re very happy that we have a lot of un-booked PUD sitting on our books. And as we develop, we’ll create more value going forward in a faster fashion. Does that answer your question?

Jeff Connolly – Brean Capital

That does. Yes. And how many acres do you have that are within the city limits?

Ed Holloway

You know, we’re probably, what, Craig, 3,000 acres?

Craig Rasmuson

About 3,500 acres would be – yeah.

Ed Holloway

3,500 acres. I do not have the number in front of me that – of how much of that is booked and not booked, but we’ll try to get that for future calls.

Craig Rasmuson

I’d say probably about half is booked.

Ed Holloway

Yes. Craig’s saying about half of that is booked and half is not.

Craig Rasmuson

40% booked.

Ed Holloway

The one thing I will tell you, very little of our reserves on booking – we have very little value from horizontal. And I keep pounding this situation, that once we get, start booking horizontal PUDs, our reserves I believe are going to double overnight, because we’ll be able to book Codell, Niobrara and maybe even possibly Niobrara C reserves on top of everything else that we have going forward.

Jeff Connolly – Brean Capital

Okay. Thank you very much.

Operator

Thank you. (Operator Instructions) Our next question is from the line of Richard Dearnley with Longport Partners. Please go ahead.

Richard Dearnley – Longport Partners

Good morning, Ed. Just...

Ed Holloway

Good morning.

Richard Dearnley – Longport Partners

Just to be clear, the production problems with the Aims/Country Club were just about line pressure issues or were there other mechanical or whatever...?

Ed Holloway

Well, it’s not line pressure issues; it’s the pressure of the well itself. These pressures are – exceed, what, 3,000 pounds of pressure, Craig?

Craig Rasmuson

Right. Yeah, an average well for us when we turn it on is between 1,800 and 2,200 pounds of pressure. And within the first 30, 60 days, you’re managing that well between 1,200 and 800 pounds of pressure, so it decreased quickly. Our problem on that pad is seven of our nine wells are over 3,000 pounds of pressure, and when you bring that pressure to your equipment a lot of that head gas will make its way and pressure up the production tanks.

So you have to minimize the number of wells you can run in a given 24-hour period of time and you’re really kind of choking them back and not letting them go full throttle at you. So it’s just the strength of the well is our issue out there. And again, we’ve added, in response to that, because it’s not a common thread here in the Greater Wattenberg.

In the heart of the Wattenberg evidently, it is, because we’re just now proving up all of our Greeley leasehold acreage, our core of the Wattenberg acreage with these wells. But with that being said, as we’ve reacted, we’ve added, as we said before, the vapor recovery and stronger equipment out there that can handle it. It’s just a matter of time before we get those – the head gas off and get those lined out with that vapor recovery that we can start producing, hopefully 60% to 80% of the wells on a daily basis, and then eventually 100% of the wells on a daily basis. Until just recently we were only doing two or three wells a day so not even 30% of our production on a daily basis on that pad. Now we’re getting to 40% or 50% here in the recent weeks and going forward obviously we want to get to 100%.

Bill Scaff

It’s a problem, but it’s a good problem to have.

Richard Dearnley – Longport Partners

Right. I understand. And the total outstanding shares, you averaged 53.1 million in the quarter. What was the total outstanding?

Ed Holloway

Total outstanding is about 54 million.

Richard Dearnley – Longport Partners

And then you’ll do another 3 million or so for the Orr acquisition?

Monty Jennings

That is correct.

Richard Dearnley – Longport Partners

Okay. And then, you haven’t mentioned any plans about Nebraska, any thoughts about testing up there?

Ed Holloway

Well, we are very excited about what we’ve put together in Southwest Nebraska and Eastern Colorado. Things are heating up tremendously all around us. We just got word earlier today that Apache is leasing north of us in our Nebraska acreage. We knew they were south and in amongst our Nebraska acreage, there’s another major player – there’s major plays all around all our acreage there. As we said in the call in our non-core Wattenberg acreage that we’re so well-positioned with long-term leases that we’re able to sit back and let everyone else develop around us and proven the best way to develop going forward. It just fits in our strategy. You’ll never see us being the first mover in any play. We like to sit back, watch, make sure the right strategy is put in place. But we have – a majority of our leases are 10-year leases which maybe a year and a half is expired on them.

Everybody else has three and five-year leases around us. So we’re really in a catbird seat sit back and watch. But that to me is one of the most exciting things about our company is that, we have a major, major asset in a developing play going forward where we have over 160,000 acres that we have probably a average cost of less than $40 an acre and we know lease costs are now pushing $300 to $500 an acre for three-year leases. So just on a leasehold basis, our value just continues to go up in that area and once Apache moves into Nebraska and starts developing there, we think that the lease price and everything else is going to be escalating even further.

We made a tour of Nebraska about a week and a half ago and all we saw were seismic stakes, seismic lines, all over going on. The activity just continues to pick up. We were at the Nebraska state auction and leases there were going in the $200 to $300 an acre range. So it’s exciting to see what’s taking place and that other people are making the move, because this area is really restricted in services. And that’s why having Apache make the announcement is so critical to us, because they’ll move in, in a big way and drag all those services with them. And we’ll be able to have advantage of having those services in place than trying to move them in ourselves.

Bill Scaff

And it gives us the option to either joint venture, monetize or drill them ourselves over time.

Richard Dearnley – Longport Partners

I understand. Thank you very much.

Operator

Thank you. And we do have a follow-up question from Irene Haas with Wunderlich Securities. Please go ahead.

Ed Holloway

We’re not going to accept that.

Irene Haas – Wunderlich Securities

Okay. Well, I’ll just take it as a no.

Ed Holloway

Go ahead, Irene.

Irene Haas – Wunderlich Securities

On the new wells that you’re drilling at Greeley that’s so high pressure and all that good stuff, what is the 30-day IP rate versus the wells outside the doughnut hole?

Ed Holloway

Well, the problem with that, Irene we can’t get 30 days. That’s our problem. These wells are so high pressured, and people don’t understand this, we’re flowing up casing. We haven’t even put tubing in the wells yet. We’re flowing up casing and the wells are actually freezing up. They are creating an ice plug in the well, the refrigeration effect going forward. So we have yet to have one well have 30 consecutive days of production and we’ve brought them on at the end of July, so we have August, September, October and now they are finally at a point where I think we can start working on a 30-day type of IP rate.

Irene Haas – Wunderlich Securities

Got you. So probably in a month or so, we’ll have a better feel as to how the two areas compare, inside Greeley and outside?

Ed Holloway

Yes.

Irene Haas – Wunderlich Securities

Okay. Great.

Operator

Thank you. And we have no further questions. At this time, I’ll turn it back to Mr. Holloway for any closing remarks.

Ed Holloway

Thank you, Ian and thank you everybody for joining in on the call. The one thing I’d like to bring out is that the majority of our discussion today was only in our Wattenberg assets. As we’ve mentioned early on in the answering question session, we do have a very strong lease position in eastern Colorado and southwestern Nebraska as well as an additional acreage position in the extended reach outside of the Wattenberg Field. We – to this day, we have assembled our really strong set of assets across a major area in the D-J Basin and just outside of the D-J Basin.

And I want to compliment my operating staff because August was a very – July and August was a very difficult time for the company and how fast they reacted to a situation that I had not seen in over 30 years with the line pressure getting to the levels that they were brought to, and that they were able to – we probably only had a production from that period of time, and especially in August, we probably only produced 50% of the days possible because of the days we had to shut down the whole pad to put on compression and what not, and still came out of the quarter almost par with the third quarter, I thought was a really strong indication of how well our operating team reacted quickly and going forward.

The other thing I’d like to mention is that of the five other larger players in the Wattenberg Field, that their average PE ratio is 24.6. Our PE ratio is at 14. I would match that our growth rate is much greater than any one of those other five that are in the Wattenberg Field and that at this point we are, and there’s a lot of companies that do not have earnings per share and we continue to drive to the bottom line, the company – that’s been our motto from day one and we’re going to continue with that, that we just keep pounding the bottom line so when the commodities markets turn, the line restrictions get back to normal we are going to take it to the bottom line stronger than anybody in our neighborhood going forward.

And we are – we’re very pleased with the number of investors and the institutional investors that are following us now and the analysts that we brought on. I think we’ve brought on maybe in the fourth quarter five or six additional analysts coverage. And I think the company is in a great position to really spring forward going into the future with a very strong growth pattern.

And I’d like to thank everybody for being on the call. And as always, we’re always available for conference calls. We’ll try to be at your beck and call when we can.

Bill Scaff

Ian you need to close the call?

Operator

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

The indication 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 there’s by no means exhaustive. All forward-looking statements should be evaluated with the understanding of their inherent uncertainty.

Factors that could cause or 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 the third-parties to honor their contractual commitments, the company’s ability to raise additional capital, as it may be affected by current conditions in the stock market and competition in the oil and gas industry for risk capital, the company’s capital costs, which may be affected by delays or cost overruns, the company’s costs of production, environmental and other regulations as the same presently exist or may later be amended, the ability to identify finance and integrate any future acquisitions; and the volatility of the company’s stock price.

I would like to remind everyone that today’s presentation will be available for replay through December 10, 2012, starting in approximately two hours. Please refer to the press release for dialing instructions. A replay of the audio webcast will be available via the company’s Investor Relations section at www.synergyresourcescorporation.com.

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

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!

Source: Synergy Resources' CEO Discusses F4Q12 Results - Earnings Call Transcript
This Transcript
All Transcripts