Richard D. Dole - Chairman, Chief Executive Officer and President
Ashley Jenkins - Chief Financial Officer and Vice President
Kurtis S. Hooley - Chief Operating Officer and Executive Vice President
Double Eagle Petroleum (DBLE) 2012 Earnings Call March 14, 2013 11:00 AM ET
Ladies and gentlemen, thank you for standing by. Welcome to the Double Eagle Year-End Financial Results and Operations Conference Call. [Operator Instructions] As a reminder, this call is being recorded.
At this time, I would like to hand the conference over to your host for today, Richard Dole, President, Chairman and CEO. Richard, please go ahead.
Richard D. Dole
Thank you, very much. Good morning. I'd like to welcome you to our call to discuss the financial results for the year ended 2012, and give you a brief update of the current activity at Double Eagle.
Joining me today is Kurtis Hooley, Chief Operating Officer; and Ashley Jenkins, Chief Financial Officer.
We are excited to be able to report that our Niobrara exploration appraisal well 41-12N had an initial 24-hour production rate of 467 barrels of oil equivalent. The production was composed of 70% 40-degree API oil, 30% natural gas. This production is only out of the Niobrara formation and does not include any production from the deeper Frontier and Dakota gas formations, which we have already completed and we're waiting for additional permitting to co-mingle the production. Our operations team is currently installing a pumping unit on the well.
We've performed numerous down-hole tests, many of which I've described in some of our earlier calls, during the drilling and completion to better understand the characteristics of the various formations. The 41-12N well is the only Niobrara production well within approximately 25 miles and is near 2 offsetting gas wells in the Catalina Unit that we operate that may be candidates for recompletions in the Niobrara. We have about a 95% working interest in this well. The company currently has approximately 37,000 net acres or 69,000 gross acres in the Atlantic Rim.
As with all initial production rates, we caution investors that while the company is pleased by the initial 24-hour rate, the sustained rate of production will not be known until the well has produced for a longer period.
Now to provide additional details and discussions, I'll turn it over to Ashley and Kurtis.
Thank you, Dick. Before we continue, I would like to remind everyone that all statements made during the conference call that are not statements of historical fact constitute forward-looking statements and are made pursuant to the Safe Harbor provision of the Private Securities Litigation Reform Act of 1995.
Our actual results could vary materially from those contained in the forward-looking statements. The factors that could cause the actual results to differ materially from those in the forward-looking statements are described in our filings with the SEC which include our Forms 10-K and 10-Q, as well as in our press releases.
For the year ended December 31, 2012, we reported total net production of 10.5 Bcfe compared to prior year's production of 9.3 Bcfe. This increase in production is primarily due to the acquisition of additional working interest in the Atlantic Rim effective August 1, as well as the full year production of our CBM wells throughout the end of 2011.
Kurtis S. Hooley
Hi, this is Kurtis. One change I want to talk about in the Atlantic Rim, briefly, is the formation of new mega unit, which is called the Spyglass Hill Unit. What the working interest partners agreed to do was to create one large federal unit where there used to be several, which included the former Doty Mountain and Sun Dog units. Spyglass Hill unit covers the southern half of the Atlantic Rim and is approximately 113,000 gross acres. Now this is done with the intent to provide some efficiencies of scale by [indiscernible] of the share compression, wire disposal and other operating costs over a larger area. The existing participating areas of Sun Dog and Doty are still intact. With the acquisition of part of Anadarko's working interest in the Spyglass Hill interest, our interest increased about 8%. The reason why I address this going forward and in this we'll be talking about the Spyglass Hill Unit a lot so I just want to give you some reference to that.
Thanks, Kurtis. Our financial results, total revenue from the sale of oil and gas, including our heading [ph] sediments was $38.9 million in 2012 compared to $45.1 million in the prior year, a 14% decline. This change is due to a significant decline in CIG spot prices, which was 32% year-over-year. And our hedges had an average price of approximately $4.55 NYMEX where we were able to minimize the impact of this decline. Additionally, the increased production helped to offset the decline in spot prices.
For 2012, we reported a net loss attributable to common stock of $14.1 million or $1.25 per share compared to net income of $8 million or $0.71 per share in the prior year. 2012 results include a noncash loss related to the change in fair value of our economic hedges of $7.9 million with a noncash gain of $13.8 million in the same prior-year period. We did realize a cash gain from settlements on our hedges in 2012 of $12.3 million.
Even in this low gas price environment, we continue to have positive cash flow from operations of $19.5 million in 2012 versus $24.8 million in 2011. Additionally, our press release includes an analysis of pro forma cash flow earnings adding back to GAAP net income, the impact of noncash items of stock option expense, DD&A, impairments and unrealized gain or loss from our hedging instruments, our before tax clean earnings attributable to common stock is $15.2 million compared to $21.1 million. The current year's clean earnings do include the sale of property at a gain of $1.6 million.
Kurtis S. Hooley
Now, one additional large expense that was on the P&L that was incurred during 2012 was an impairment of almost $5 million and that was primarily related to our exploration well in the Niobrara. We began to wind this appraisal well in 2011, which targets the Niobrara, Dakota and Frontier formations. We encountered numerous pressure zones and delays due to wildlife stipulations. In the first quarter of 2013, as Dick said, we were able to begin production. As noted earlier, our 24-hour IP was 467 Boe. When we reviewed the expected future production based upon the formation, our logs and the estimates of Niobrara formation geological makeup, come up with our best estimate of future cash flows and then we wrote off the remaining balance of the costs incurred, which relate to the true exploration in that area.
Our FCC proved reserves decreased from the prior year 78.1 Bcfe compared to 136.6 Bcfe. We had negative revisions of approximately 47.8 Bcfe and proved undeveloped reserves due to the 40% decline in natural gas prices used in the estimates, which are calculated in accordance with the FCC rules. Additionally, some of our nonoperated properties, the development plan is uncertain, which would have precluded them from being included in our FCC reserves. This decline also resulted in a significant decline in the PV-10 value of our proved oil and gas reserves. In our press release, we did provide what our reserves would have been if a forward strip had been applied to the December 31, 2012 reserve and assuming all the available PUDs were developed. The forward strip pricing resulted proved reserves of 132.5 Bcfe and 162 million of PV-10 value. We do not include any of the Niobrara well estimates in our reserve report. Our next borrowing base redetermination is April 1 and despite our decrease in reserves in the FCC price case and although, no, we cannot know for certain what the pricing and outcome of the April 1 review will be, we currently expect our borrowing base will be reaffirmed an amount in excess of our current outstanding borrowings.
Kurtis S. Hooley
And now in 2012, we did spend about $25.7 million in financing activities, which included the purchase of additional interest in the Atlantic Rim, the participation in the Pinedale Anticline drilling and completion and the completion of the Niobrara well. In 2013, we currently have budgeted $14 million of capital spending. We do expect to continue to have drilling in the Mesa "B" unit of approximately $5.5 million, frac-ing additional formations in our Catalina CBM wells, which makes up about $6 million of the CapEx and the remaining $2.5 million is set aside for potential seismic and land related costs.
Now we may increase this budget amount to further develop the Niobrara formations in the Catalina Unit, but we will make the determination once additional information is obtained from the production of the 41-12 well. We have approximately 69,000 gross acres that, with additional regulatory approval and permits, have possible opportunity for development in the deep formation. On an 80-acre spacing that would be equal to about 862 wells. Part of this assessment we made is the opportunity to drill directionally, slant or horizontal in the formation for better recovery.
As it relates to the development of Spyglass Hill Unit, we have not received any indication or approval for extension request from the operator, which is Warren Resources. To hold the unit together, 25 CBM wells must be drilled by June 10 of this year and another 25 has to be drilled by June 10, 2014. If we do receive AFEs related to drilling these wells, we'll have to assess the economics and the operating status of the existing PAs before we'll commit to participate.
Richard D. Dole
Thanks. Looking forward to the upcoming year, we're going to focus our efforts on assessing the Niobrara development. We're working on a full field development plan for the Niobrara, Frontier and Dakota and for the coal bed formations. We will consider reentering 2 existing wellbores that are already drilled to the Dakota formation for recompletion in the Niobrara. We'll continue to exploit our Catalina CBM volumes and look for complementary properties or merger opportunities.
And with that, I'll open the call for questions.
[Operator Instructions] And we'll take our first question Ho Shang Deroga [ph] from MLV & Co.
Congratulations on the Niobrara well. It was a really good successful well. Question on this one. I understand that you guys spent over $11 million to drill this well and I understand it's the first well, but if you overlay a typical Niobrara-type curve on this one, what costs should we look at for this well, this play to be economic and have like a 30% to 40% IRR?
Richard D. Dole
Well, to explain the costs, this was a very atypical well. We went through 3 different pressure regimes. And when you go through a different pressure regime, I won't go in the details, you have to handle your circulation and your drilling mud in a different way. So if you've got a high-pressure regime, you need more weight to your mud. If you've got low pressure regime, you need to be under balanced. We anticipated 2 of the 3 pressure regimes and did not anticipate the third. So the majority of the costs over what we expect these wells should cost was attributable to that, and a small part of it was attributable to some of the science work that we did down hole. But having said that, we're -- the idea for the appraisal well was to get down and see what you got. We think that the AFEs on these wells could be anywhere from 3 million to 5 million maybe 6 million and it depends on what kind of frac-ing fluids we decide to use going forward, or whether we're going to do horizontal or whether we're going to slant drilling, whether we're going to do vertical drilling. So we're in the process of -- that will all be a part of the full field development plan and it'll also be very dependent upon the sustained production rate that we get out of this well.
Kurtis S. Hooley
And we always caution people, it's hard to put a typical Niobrara decline curve in a basin that really doesn't have any existing wells on. The DJ Basin has 300 feet of pay, we're in 1,500 feet. We're 6,000 feet deeper. So we're going to see how this well produces and get the science behind it. So we're not really going to putting out any decline curves and how do you do 30% IRR that it's just not really even ascertainable at this point in time that we give it with any certainty that we'd want to put out.
Great, appreciate it. I understand that. And what about the 2 wells that you already have in your Catalina Unit and do you -- what sort of costs should we look at for those 2 wells that you would go down and complete in the Niobrara? And would that be in 2013?
Richard D. Dole
Yes, if the results of this well continue to encourage us as it is, yes, those would be done in 2013. And it depends again on how we decide to frac the wells. There are a variety of different approaches you could have. It could range anywhere from $1 million to maybe $3 million depending on what we decide to do with it, but we haven't put the AFEs together for that so that's a wide range, it's a wide range because we really haven't put the pencil to the paper yet.
Our next question comes from Don Cutson [ph] from RBC.
My question is, in terms of the options that you have given this well, can you discuss what options you are considering in terms of field development? Are you considering JVs? Are you considering purchases? Can you give us maybe the list of options that the company's considering at this time? That's question one. And then question two, can you use the existing wellbore to drill horizontally if you elect to do so?
Richard D. Dole
I'll answer the last question first, and the answer is yes. We intentionally drill -- use a larger casing that we really needed to do, in case we decided that there was a sweet spot. We wanted to drill here horizontally. We're going to evaluate horizontal drilling but when you have 1,500 feet of potential pay, in a vertical sense, sometimes you leave too much behind with just a single horizontal well. Maybe you can do multiple horizontal wells and that might make a sense later on. But I think, for right now, in this well, we're going to continue to assess it on a vertical basis. We'll have 2 other wells that we can reenter that are vertical wells that we'll be able to continue to assess it. I would guess, and I'm just guessing at this, that some kind of directional drilling will make economic sense at some point in time, but when I really kind of understand what we have. The second part or the other part of your question, when we started getting serious about de-risking the Niobrara, which was more than 2 years ago, we had a lot of interest from private equity to support us in that effort. We made a conscious decision to de-risk the acreage with our dollars, which we hopefully have done now or will have done even further with our reentries. And given how our stock reacts in the market, we may decide to raise capital on our own, or we may decide to do a joint venture. The one thing about a joint venture we would find attractive, and it would not be a financial joint venture but a strategic joint venture, is to attract some deep expertise in this kind of drilling from companies who have been doing it in the Bakken and the DJ Basin and other places. So that would also be an item that we would consider on whether we go it alone or go it with a partner.
Okay. And then if I could just one follow-up would be, can you give us a time line as to when you might report something on this well going forward? Are you prepared to do that at this time, just when we can expect some kind of a follow-up on decline rates and so forth?
Richard D. Dole
Usually people wait for 60 to 90 days, I guess that might be a good time line.
[Operator Instructions] Our next question comes from William Kidston from North & Webster.
Just a quick question about your midstream infrastructure. Can you give me your utilization, currently and future plans to ramp up that utilization?
Richard D. Dole
We have about a 25% utilization on our infrastructure. Obviously, as the coal bed develops to the South and Catalina develops those volumes will go through that pipeline and the, any Niobrara production, which will be substantial if these wells continue to perform the way we think they're going to perform, will be additive to that. We are looking at the various ways of monetizing the pipeline at this point in time, but we don't have anything specific to discuss on that. But we don't seem to get much credit for it in our stock price, so we're going to see if there isn't a better way to use the -- create the value for the shareholders through some form of monetization, whether it would be a structured financing or a sale on lease back or whatever it might be.
Do you guys have any plans to extend at this point in time or are you just waiting to see what you can get in the market for the current pipeline?
Richard D. Dole
Yes, we're not -- we don't have current plans to extend. We did a few years ago, go and obtain some right of ways and that would allow was to extend, but we haven't done that yet. We have to have a larger volume throughput to justify doing that.
At this time, we have no questions waiting.
Richard D. Dole
I'd like to thank everybody for participating today. And I hope you have a great weekend.
Ladies and gentlemen, this will conclude our conference. Thank you for joining us today.
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