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Double Eagle Petroleum Co. (NASDAQ:DBLE)

Q4 2008 Earnings Call Transcript

March 12, 2009 11:00 am ET

Executives

Richard Dole – Chairman, CEO and President

Kurtis Hooley – SVP and CFO

Steve Degenfelder – SVP of Exploration and New Ventures

Analysts

Mark Lear – Sidoti & Company

Blair Salisbury [ph]

Tom Hayden [ph]

George Robinett [ph]

David Vanture [ph]

Pat McLaughlin [ph]

Operator

Ladies and gentlemen, thank you for standing by. Welcome to the 2008 year-end results summary conference call. At this time, all participants are in a listen-only mode. Later there will be an opportunity for questions and instructions will be given at that time.

I would now like to turn the conference call over to our host, Richard Dole, President, Chairman and CEO. Richard?

Richard Dole

Thank you, Anna. Good morning and welcome to Double Eagle’s call to discuss fourth quarter and the year 2008 results. Joining me today is Steve Degenfelder, Senior Vice President of Exploration and New Ventures and Kurtis Hooley, Chief Financial Officer.

Given the current volatility and uneasiness in the energy and capital markets these days, our stock, like all our peers, have suffered significant decline over the past 180 days. But the basic fundamentals and strength of this Company are still solid as evidenced by our 2008 production, revenue, earnings, and returns growth, and the increase in our credit facility and borrowing base in 2009.

2008 was the strongest year ever for Double Eagle with record production from the core assets in the Atlantic Rim. This is primarily a result of production from the 33 Catalina Unit wells drilled in 2007 and put into production in the first nine months of 2008. Gross daily production from the Company-operated Catalina Units was approximately 30 million cubic feet per day at December 31st, 2008. In addition, we are seeing encouraging results from the Sun Dog and Doty Mountain Units in the Atlantic Rim, are expected to increase from our Pinedale interest.

Now, Kurtis will discuss the financial results.

Kurtis Hooley

Thanks, Dick. Before I discuss the Company’s year-end 2008 financial results, I’d like to remind everyone that all statements made during this conference call that are not statements of historical fact, constitute forward-looking statements and are made pursuant the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. Actual results could vary materially from those contained in the forward-looking statement. The factors that could cause the actual results to differ materially from those in the forward-looking statements are described in our Forms 10-K and 10-Qs, other periodic filings with the SEC, and in our pres releases.

We are pleased to report net income attributable to common stock for the year ended December 31st, 2008, was $6,658,000 or $0.73 per share compared to a net loss of $13,413,000 or $1.47 loss per share for the year ended December 31st, 2007. The net income attributable to common stock in the year ended 2008 includes $3,723,000 paid in dividends to the holders of our Series A Preferred Stock.

As in prior periods, our press release issued this morning included an analysis of pro forma cash flow earnings per share. As we have increased our price risk market activities, the non-cash impact of accounting for hedges under FAS 133 has and will continue to have a significant impact on our GAAP earnings per share and in my opinion it doesn’t really provide the readers of financials an easy way to obtain the true results for the Company during any period.

For the year ended December 31st, 2008, we recognized gains on our derivative instruments for our mark-to-market hedges of $2,698,000. With the constant change of volatility in the NYMEX and CIG gas markets, this gain, which is non-cash will change during future periods without any corresponding cash or volume related activity.

Our pro forma cash flow per diluted share, adding back the GAAP net income – adding back to GAAP net income the effect of the non-cash items of stock option expense, DD&A, deferred taxes, and deducting the unrealized gains from price risk management, the net cash flow attributable to common stock for the year ended December 31st, 2008, was $21.2 million or $2.31 per share.

When we look at our 2008 results, the significant improvement over last year is attributable to several factors. First, our net production for the year was 6.7 billion cubic feet versus 3.0 Bcf for 2007. This represents an increase of 123% year-over-year. The increase is primarily attributable to the success of our Catalina drilling program. We recognized average daily net production at Catalina for the year 2008 of 10.9 million cubic feet per day or a 167% increase over the 2007 production of 4.1 million cubic feet per day.

Secondly, we were able to realize an average price per Mcfe of $6.23 versus $5.33 per Mcfe in 2007. At December 31st, 2008, we still have seven million cubic feet per day under fixed price contracts that we entered into in early 2007 at an average CIG price of approximately $5.84, which – these contracts expire at various times through 2009. We also had another 11 million cubic feet per day hedged under various instruments at an average price of $7.93 that go through March, 2009, and of which eight million cubic feet of those continue through December, 2009, with a CIG price of $7.34.

The combination of increased volume and realized prices resulted in production related sales revenue increasing by 175% to $46,635,000 for the year-ended December 31st, 2008, from $16,954,000 in the same prior year period. Overall, the production volume increase account for approximately 89% of the increase in revenues and the price increase account for approximately 11% of the increase for the last quarter.

We also continue to see low production cost and improvements in our overall – over prior year results. This is due to improved efficiencies in our operations as well as in 2007 we did have some residual cost related to workovers performed. We continue to be a low-cost operator and are looking to improve this in 2009. The reduction in the cost per Mcf was offset by an increase in our DD&A expense for 2008 due to the increase of production volumes and the capital additions added since the same time in prior year.

Now, turning to our balance sheet, there is a couple of accounts I would like to discuss. As shown on our Form 10-K accounts receivable at year-end had a balance of $21,381,000. A significant portion of this balance relates to the amounts receivable from third parties for normal production payments and reimbursements of joint interest billing cost. A small portion due from our working interest owners for their allocated portion of our 2008 project costs.

The outstanding borrowings under our line of credit has increased to $24,639,000 due to the costs being paid related to our 2008 Catalina development project and third-party billings for the wells drilled in Pinedale Anticline as well as in the Sun Dog and Doty Mountain Units at the Atlantic Rim.

After year-end accruals, our working capital was a negative $6,314,000 at year-end. This is due to several factors. As you all know, the significant portion of our drilling takes place in the third and fourth quarters of each year in the Atlantic Rim due to environmental stipulations. Therefore, a significant portion of the costs are received in the fourth quarter. The drilling related cost had increased significantly during the year due to all the drilling activity, so the overall cost increased.

Also, due to the financial market collapse in the third and fourth quarters of 2008, the banking industry, including our lenders basically stopped all loan extensions and discussions. We also had acceleration in billings from our third-party operators versus historical trends.

As announced a couple of weeks ago, we finalized our new credit facility with our lenders, which provide for a 50% increase in our facility to $75 million and an increase of 28% in our borrowing base up to $45 million.

Given the questions we recently received and what seems to be everybody’s concern over liquidity, we would like to turn to our 2009 plans for CapEx and where we see liquidity. As shown in our 10-K filed this morning, we plan to have capital expenditures between $10 million and $20 million for 2009. A significant portion of these expenditures will be our continued participation in the Pinedale Anticline Unit operated by Questar [ph].

Based on the latest information we have, they are planning to continue to develop these fields. They may pull back some drilling in the future but we won't know until we get further in the year. The remaining portion will be used on well enhancement projects in the Atlantic Rim to increase production and operating efficiencies at the Sun Dog, Doty Mountain, and Catalina Units.

In order to maintain and control our liquidity, we do not plan nor does Anadarko plan to drill any new wells in the Atlantic Rim in 2009. We believe in this market that maintenance and improvement CapEx is the most prudent use of our limited liquidity.

With a significant pullback on drilling and service related work in the Rockies by oil companies, we are seeing prices for drilling materials and services dropping. We believe this will continue during 2009 and is key to help reduce cost and improve the economics of our wells in the future. We are aggressively tackling all of our costs, specifically the cost of operating our wells, and we have begun talks with our non-operated fields’ operators on how we might jointly drive cost improvements. In addition, we are reducing our G&A costs by overall tightening of the belt to help weather this storm.

As I discussed above, our borrowing base was just redetermined in conjunction with our new credit facility and will come up for redetermination at the end of June. The price desk [ph] that was used in our redetermination was significantly lower than in prior years and we do have additional producing reserves that will be added to the borrowing base as 23 new development wells that we have drilled as part of the 2008 project are expected to on production by the next determination date. Now, obviously, we do not know what the new borrowing base will be at the redetermination as it is based on both the bank’s expected pricing models and the actual volume of our new production we have online.

Based on the information we currently have, we believe we will be able to manage our liquidity through 2009 and remain in compliance with all of our credit facility covenants. Looking ahead to the next year, the forecast of cash flow from operations, the gas price available to producers on the Rocky Mountains as well as the amounts available under our current credit facility will determine the funding available and will redirect [ph] our funding for our 2009 capital projects. Currently, we expect to continue to participate in our non-operated Pinedale properties drilling program and again in the Atlantic Rim we will be focusing on enhancement and production improvement projects.

As part of our ongoing assessment of price risk we have entered into numerous hedging instruments that we believe allow us to manage and anticipate our cash position in the future. At December 31st, we had 18 million cubic feet per day of natural gas hedged under various instruments that expire during 2009. We also have an additional eight million cubic feet per day under contract for counter 2009 at $7.07 per Mcf. And subsequent to year-end we entered into a gas lock agreement for 12 million cubic feet per day at a price of $4.83 CIG for calendar 2010.

For any more information, I refer you to the 10-K for a more detailed discussion. I will not turn it back over to Dick.

Richard Dole

Thanks, Kurtis. Management has and continues to be focused on drilling our asset base and effectively deploying the capital that’s available to the Company. We will continue to assess the timing of our future development in the Catalina Unit. In addition, Anadarko, the operator of Sun Dog and Doty Mountain Units continues to expand and improve their production operations in these non-operated Atlantic Rim properties. We have Atlantic Rim midstream assets and opportunities that could have significant potential for further commercialization.

Pinedale has additional locations to be drilled with substantial potential remaining reserve increases. And there are several other offset locations in the Waltman area that provides opportunities for further development. And while these projects will require multiple years of development, we continue to review new ventures that are complementary to our Company’s asset portfolio and our core competencies.

At December 31st, 2008, the Company’s proved reserves estimated by its independent reserve engineers was 88.9 Bcfe compared to 73.7 Bcfe as of December 31st, 2007. This reflects net proved reserve additions of 26.6 Bcfe or 36% and an increase of 21% in proved reserve year-over-year, considering the reduction of 2008 production of 6.7 Bcfe. The 2008 reserve additions are approximately four times the 2008 production. This increase in estimated proved reserves reflects adding proved reserves in the Company operated Catalina Unit and the non-operated Mesa Units in Pinedale Anticline and also includes a decline in proved reserve from the non-operated properties in the Atlantic Rim, resulting in part to declines in year-end gas prices.

As you know, the Company can only control certain aspects of the Company’s valuation. Accordingly, we will continue to focus on increasing productions, reserves, executing on new projects, and continuing to pursue our market awareness program. Over time, we believe the market will respond favorably to these factors.

I will now open up the call for questions.

Question-and-Answer Session

Operator

(Operator instructions) We will take our first question from Mark Lear.

Mark Lear – Sidoti & Company

Good morning. I was wondering, just focusing on Catalina, how many net locations do you have remaining in that project area?

Richard Dole

In just the Catalina Unit?

Kurtis Hooley

Well, the Catalina Unit, if it was fully developed, assuming fully developed status would be approximately 250 wells and we have 70 producing wells to-date. So, I guess I would ask you to do the math because there – I can't guarantee the fully development status, as you know. But based on the size of that unit less the number of currently producing wells that would be the number.

Mark Lear – Sidoti & Company

Understood. And just was kind of curious how that one – the discovery of the fault, does that impact or risk the project area a little differently for you guys?

Kurtis Hooley

No, Anadarko has encountered faults there as well and you would like to identify those but many times the only we can identify them is with the drill bit. There they don’t coincide with the surface faults. And so this unfortunate occurrence was the same as Anadarko had encountered up in Doty Mountain and it allows us to identify where those are and prevent us from drilling those again, but it does not condemn the acreage to the West.

Mark Lear – Sidoti & Company

Understood. Of the wells you drilled in ’08, are any of those currently online or still waiting to get hooked up?

Kurtis Hooley

Well, at year-end, at 12/31, we had five online and we last year just completed in bringing the rest online as we speak. We do expect that all of those be on – able to produce by the end of March 2009.

Mark Lear – Sidoti & Company

And then I guess the initial performance of those wells and maybe discuss how it kind of compares to what you saw from last year’s program and maybe even kind of an update on how those wells that have been on six to 12 months, how they have been performing to-date.

Richard Dole

(inaudible) I will take it – a shot at that, Mark, this is Dick. The new wells are – it’s really too early to tell. We don’t even have the full compressor (inaudible). We got one more compressor to put up and won't know that until we can actually produce them at full production. So, time will tell on those. I believe, Steve, that the wells that we drilled last year are holding up quite well and probably averaging 600 to 700 –

Kurtis Hooley

On average, those, yes, so that the Pod B wells are staying in line with that and what we’ve always said and I think will hold true to this that we hit a very good spot there in Pod B and it continue. We are still estimating that the Pod C, and Steve can correct me, are going to be consistent with what we saw historically in the coal bed methane. We may be all conservative on that, but we don’t want – because we don’t have the results back yet. We are still looking for beginning around 200 going up to 400 over an 18 month period curve and then decline on a historical rate. That’s what we are looking at, and I think that’s where we would direct everybody to as we said in prior conferences. And Steve is that–?

Steve Degenfelder

Yes, I think that’s very consistent with our perspective. We have better performing wells both in Doty Mountain that are directly adjacent to the North and our Pod B wells, but we feel like it’s better a conservative approach to that production. In addition, we have a couple of wells in Pod B and as you might be aware, we don’t install tubing in a well if its flowing to the surface when it’s initially completed. Several of those wells have now grown off that initial hit of gas and we are waiting to put until spring gets here to put tubing in which will reestablish that production. So actually we have few wells that despite that average production figure, we look to add to this spring when we get in there and put tubing in the well.

Mark Lear – Sidoti & Company

That’s helpful. Thanks a lot.

Operator

Our next question is from Blair Salisbury [ph].

Blair Salisbury

Hi, congratulations for the – bringing the Atlantic Rim development process to successful fruition.

Richard Dole

Thank you.

Blair Salisbury

My question involves the fracture stimulation process that currently you and Anadarko are doing right now. How long has that been instituted?

Richard Dole

Well, Double Eagle has been doing it since what 2002 when they initially did the pilot wells. Anadarko just started piloting some of their wells in 2008. And I think, Steve, the results have been pretty encouraging (inaudible).

Steve Degenfelder

They have been. Anadarko – Double Eagles, as Dick said, began fracing their wells since really inception and brought that technology up to this area from what used in the Namratan [ph] Basin. And so our wells have been smacked [ph] from day one, and we continue to do that even with our Pod C wells that we just drilled this past fall. Anadarko has not in the past embraced that technology and – but started to up in the Doty Mountain area where the coals are somewhat thicker and have experienced some extremely encouraging results. Some of their wells have tripled and quadrupled in production in both gas and water with some of the rates exceeding 500 Mcf a day and just recently we had a couple of wells that exceeded a million a day from Anadarko in the Doty Mountain area. And while these rates are very, very encouraging, I would just caution everyone that we need to see those rates continued to start celebrating that we have some additional gas to count.

Blair Salisbury

Right. I wondered what might happen over time in the decline rate after you’ve reached the peak there. Is it faster or–?

Steve Degenfelder

You know, we – in comparison what you see, if you are acquainted with any of the other shale plays throughout the United States that rely on fracture stimulation to get some high rates of production, especially on the Pinedale Anticline and Barnett Shale and Bakken Shale, you see this blast of initial production with about 70% decline rate that first year. We are not seeing that – this fracing seems to open up those cleats that are in the coals and allow for the production to come on and not rely only on that fracing to establish some rates of production that the shales enjoy, at least initially. Did that answer your question?

Blair Salisbury

Yes, it sure does. I sure appreciate it. Thank you.

Operator

Our next question is from Tom Hayden [ph]. Go ahead, Mr. Hayden.

Tom Hayden

Oh sorry. I have a couple of questions. Regarding the well that was abandoned, can you give me the depth in the (inaudible).

Richard Dole

I will ask Steve, see if he can get –

Steve Degenfelder

It was the 1791-11-31 well and it was the farthest west of our Pod C well you know without – I can – I will guesstimate on the depth of that around 1800-1900 feet. I just don’t have my computer open in front of me. And our geologists estimated there was about 700 feet of throw [ph] on that fault and – where he thought it was going to be between 11 – 5000 feet throw and so what that means to us is that as we move west, we thought the wells would have to be a little deeper because we know the fault was there, we just didn’t plan on hitting it. So that the one positive thing is that it indicates that wells to the west will not have to be drilled as deep to access the same coal that we experienced in the eastern part of Pod C.

Richard Dole

As far as the cost, the dry hole cost of that, $500,000.

Tom Hayden

The 30 million cubic feet that you mentioned on December 31st, was that net for Double Eagle.

Kurtis Hooley

That was the production at Catalina at gross 88 [ph].

Tom Hayden

That’s gross or net?

Kurtis Hooley

That’s gross, the 30 million, yes, it was 30 million.

Tom Hayden

The lower working interest percentage in Catalina, what was the effective date going down–?

Kurtis Hooley

That would be October 1st when that – those new drilled wells required a PA revision and so our interest went from 73.845 down to 68 and change.

Tom Hayden

68, I am sorry, I misquoted that. Well, do we see another reduction, probably not in 2009, correct, because we are not drilling anymore new–?

Kurtis Hooley

Yes, no reductions.

Tom Hayden

So, no reduction in 2009. What’s the most current daily net production you can release to me?

Kurtis Hooley

At the end of the year, I believe, our net production for what Catalina or for the Company?

Tom Hayden

Either one. Both would be great.

Kurtis Hooley

I think the Company was around 28 million or 29 million a day and Catalina was what 18?

Steve Degenfelder

Almost 13 – 30 times 68, so it’s around 20.

Kurtis Hooley

Okay, just under 20.

Tom Hayden

Just under 20, okay. Can you release a more current figure, March, April, I mean February.

Kurtis Hooley

We don’t give guidance. We will be able to do that at the end of the quarter.

Richard Dole

Correct.

Tom Hayden

Okay. What percentage of quarter one 2009 is hedged? I am looking at your numbers and I don’t – I can't quite get the percentage.

Kurtis Hooley

Right now approximately of our Q1 production is we assume our current production rate approximately 70% is hedged.

Tom Hayden

Okay. Thank you. I got a couple of more. What’s the payback let’s say on the most recent wells drilled? And my question here really is going to what’s the breakeven point for these last wells drilled in the program, $3 or $2.50–?

Kurtis Hooley

Well it’s – we are still at about a little over $1-$1.50 finding and development cost and depending on what the production cost is, we know we got a lot more wells that will absorb some of our infrastructure, we have not computed, but we think the go forward production cost per Mcf, but I think last year it was about $1.25?

Steve Degenfelder

Yes, right now for Catalina a little bit. That is conservative approach.

Tom Hayden

So, add the two together, $2.75 is your cost, so–?

Kurtis Hooley

Yes, that’s sound about right.

Tom Hayden

In your statements, you said you have a good continuing expectations of 2009, so I would have thought your breakeven was around $3 or $2.75, sound like a very good number.

Kurtis Hooley

I think it is. And quite frankly, what we haven’t factored in is – and because we can't measure it, but we think there is a lot of production growth from our existing wells by focusing on enhancing some of the down hole aspects of it. And if that happens and that creditably [ph] drops down both the LOE cost per Mcf and of course the finding cost per Mcf.

Tom Hayden

Did Netherland Sewell then increase the number of the life span of the wells, some of the wells in their analysis for December 31st.

Kurtis Hooley

Well, they can't seem to get over that. They are still doing volumetric calculations which puts us–

Tom Hayden

Still producing.

Kurtis Hooley

Hey listen, I am with you. Maybe you can help us figure – get that figured out. We’re – I will tell you what we are doing is that we commissioned last year a more scientific study of the technical data you know the core, we took some cores, the logs, the testing of the water, the production profiles. And we’ll be reviewing that in April with the consultants that we hired. And I am hoping that we’ll be able to explain why our production rates are – why our reserve life should be more representative based on our production rates as opposed to the volumetric calculation of the thickness of coal and the gas content in it. And I think I have said before that it’s my personal opinion that we are getting gas from other formations that we are not getting credit for in our reserves.

Tom Hayden

I concur and I look forward to that April (inaudible) release, whenever you can, maybe midsummer. Thank you.

Richard Dole

Yes, okay.

Operator

(Operator instructions) We will take our next question from George Robinett [ph]. Go ahead, Mr. Robinett.

George Robinett

Dick, what’s the situation now in Nevada and what’s it costing us annually to maintain those leases?

Richard Dole

Well, we – for (inaudible) purposes we’ve written off the leases in Nevada. And we are not renewing any – extending any rentals. So what we are trying to do is find somebody interested in the leases that we do have currently under paid rentals, but we are not adding any – we are not paying – we are not renewing any of them.

George Robinett

Okay. And when we talk hypothetically about what are our opportunities in 2009 kind of Steve Degenfelder job title, what – if we are not going to do any exploration and we are looking for other opportunities, realistically could we finance the acquisition of Warren’s interest in unit, for example?

Richard Dole

I mean we haven’t – you can always finance it. It’s a matter of what is it costing. Let me put it this way. Because Double Eagle has been a survivor of this downturn and we believe that Double Eagle will be a driver the opportunities. And we’ve been approached by various capital groups to talk about how they might fund and joint venture with us. An aggregation that could include assets, it could include companies, and we are in the very early stages of reviewing those opportunities. I mean it’s like a big funnel with all the stress that so many companies are under. The opportunities are coming into the top of the funnel. We are trying to sort through them and qualify and evaluate them and not let them divert us from increasing the value of the assets that we already have in our portfolio. We haven’t said that, we are seeing s a significant amount of interest in people trying to see how they might associate with Double Eagle.

George Robinett

So, obviously, they are looking beyond the summer potential for shut-ins and then the price dislocations we are going to see this summer. And that’s great and I am glad to hear that you are doing that. And on our pipeline what percentage of the capacity is being used on our Company-owned pipeline at this point and is there anybody bypassing us or how can we get more gas through there?

Richard Dole

Well, I mean it’s an issue that we are dealing with now. It’s about 25% of the capacity of the pipeline is being used from our Catalina Unit. There are opportunities and we are in discussions with other third parties about transporting additional gas. And while we don’t have anything we could announce, we can – I can tell you that we are exploring those options as we speak and if and when we get anything that’s meaningful we’ll obviously report it. But it’s probably a pretty good time. I don’t think anybody is going to be putting any capital and to try and bypass our pipeline, not at least in the next couple of years. So it’s a good time to see if there isn’t some way that we can expand the throughput, and we’ll be working on that this year.

George Robinett

Good, okay, glad to hear that. So then when we talk about our core competency, are we pretty much focused on our unit in the Pinedale and we can stick to our fairly narrow geographic focus realistically or are we thinking outside that box?

Richard Dole

Well, that is our I mean kind of there is different kinds of competencies. We are very competent in how you deal in the regulatory environment in – with the federal government and the state of Wyoming. So that allows us to identify and execute on opportunities that others who are maybe not as competent could do. We are also becoming very knowledgeable in this Atlantic Rim asset, which as you know is really a new asset. And the reason for commissioning the study I referred to earlier is there is probably huge amount of opportunities and there is a huge opportunity to make miscalculations of where you want to be in the Atlantic Rim and we think there is a lot to do there. And I haven’t said that – geologists, land engineers, there are certain functions – the functionality of those skill sets are quotable [ph] to other opportunities. So, I kind of talk around the issue, but we do stick to what we really are good at, what we have in our portfolio, because there is so much growth, but we can't ignore opportunities that we think the risk-reward ratio is high. And that would obviously require us up and one of our staff and skill set if we took on anything additionally – many to additions.

George Robinett

Alright. Well, I appreciate the color on these issues and thanks and I think you guys are doing a good job with everything that can be done in this day and age. Thanks.

Richard Dole

Thank you.

Operator

Our next question is from David Vanture [ph]. Go ahead, Mr. Vanture.

David Vanture

Good morning guys. I’ve got a couple of questions, some of which have been partially answered already. Previously you said that the first quarter production was about 70% hedged. Could you provide us – or go through the where we would be at the end of the second, third, and year-end quarters?

Kurtis Hooley

Yes, actually, if you look in the press release, we actually laid that out for you as for as total volumes by quarter and the CIG average price applicable to that for the next three year we got that. So far in Q2, we have 1.3 B at $6.68, we have Q3 859 at $7.12, and Q4 we have 767 at $7.27. So – and then you look at 2010 and 2011 if you’d like to kind of see the total volumes we have.

David Vanture

I was just trying to break that down into percentage as opposed to the 70% in the first quarter.

Kurtis Hooley

I can do that for you. My calculator is probably faster than yours. 70% Q1, 49% Q2, 31% Q3, and 28% Q4.

David Vanture

Okay. And that’s without any additional hedging, which may or may not happen if opportunities arise?

Kurtis Hooley

That’s correct.

David Vanture

The way I understood of the Pod C wells five are already online and another 19 are going to be coming online, is that right?

Kurtis Hooley

Another 18 because we did have one dry hole.

David Vanture

Okay, another 18. Okay. And the reserves of 88.9 at year-end, can you even any of you just take a wild guess what you might be looking at – and it would be a wild guess – for the end of 2009?

Richard Dole

Nobody is raising their hand in here, David, so I guess not.

David Vanture

Turning to other areas, is there any life in Christmas Meadows these days?

Steve Degenfelder

Yes, this is Steve, David. We are still working on it. Nothing that we can announce, but it’s not dead in the water and – but the best I can say right now it’s – any project of that magnitude and not much risk that is still being worked on is a positive. So, with that I got said enough. I am still working on it and hopefully get something done on it before the leases expire.

David Vanture

Yes that would be a great shot because it still looks like a chance. What about – can anybody discuss the Waltman situation and any other prospects other than the Atlantic Rim and Pinedale?

Richard Dole

We will be completing the second Waltman well – we are completing or we have completed. And we haven’t put it on production. We actually don’t have all pipelines in place, but when do you think it might go on?

Steve Degenfelder

Probably, right about two or three weeks. We completed our fracs this weekend and we are flowing back right now, but we are still getting a lot of the CO2 back so you get methane gas and then a burp [ph] of CO2, but all the fracs went as planned this past weekend. And we took – I was told, about 250,000 pounds of sand in, and in three good fracs. And then we’ve got several other zones that we have put a frac on. So, we are optimistic and might fix it. It required us to put a pipeline in – bored a hole underneath the highway and hooking the compressor up, but we are very encouraged by our – by last weekend’s work. And then we’ve – trying to evaluate other locations that we have the ability to drill if economic conditions and the wells’ performance indicate that we should.

David Vanture

Could you end up with more than three there. I mean how many total could you end up with?

Steve Degenfelder

Well, we’ve got more than three possible locations, but in the past I’ve seen people make projections based on one individual well’s performance and so I would – we got more than – I’d say we’ve got maybe a total of 400 acres there that we could drill wells on, but that does not mean that they are all productive right. I would just – as we go we’ll evaluate the production of each well and how any offset might perform.

Richard Dole

But there are potentially eight locations.

Steve Degenfelder

Yes, that’s the locations.

David Vanture

So, depending on how things turn out, additions somewhere between three and eight, is what we are looking at?

Steve Degenfelder

Actually, right now, we are – we’ve acquired a little bit more acreage and depending on the – how that sand kind of meanders to the south or southwest, we’ll – could even increase that figure. It’s just time will tell.

David Vanture

Are there any other locations like I say other than the Atlantic Rim and Pinedale that you would be working on this year?

Steve Degenfelder

No, we continue to participate in Whiskey Butts, which is operated by British Petroleum or BP. But that’s relatively small participation, although as it accumulates over time it’s meaningful to us, but there are no other exploration things that we have in our budget, quite frankly. Given our assets it makes more sense to deploy capital on assets that we know and can measure the risk and reward better than those that we don’t know. So, we are keeping our capital focused on increasing the production from what we’ve got.

David Vanture

Right. Now that makes sense. With the Anadarko early fracing success, you think that they might – it’s hard to say – but do you think that they might be able to have enough success in the properties that you are part that it might make a significant increase in your production reserves?

Steve Degenfelder

Well, just considering the fact that in Doty Mountain we own 18% of 60-70 wells and if the results continue in the doubling or tripling or quadrupling phase, that could become more than we are getting out of Doty Mountain now.

David Vanture

I mean, so you could potentially double the production reserves that you are getting out of there then, if they carried forward with it?

Kurtis Hooley

I wouldn’t go as far as – now don’t move this to reserves, David, because the reserves are based on the thickness of the coal and the evaluation from the reserve engineers and we did – we talked at ours, volumetric is probably hold a little bit truer in those coals until we see their production. So we want to be very careful when we see say this, that one, we don’t operate that area, but, two, the reserves that we get from Doty Mountain are pretty indicative of the thickness of the coals. So I am cautious – hurtle that fence on this and get the wrong idea.

Richard Dole

Yes, fracing adds to accelerating production.

David Vanture

Yes, okay. And lastly, Dick, you made some reference to the funnel with all the things that are being filtered down. Is there any way to characterize the different types of things that might come out of that?

Richard Dole

No. They are numerous. I mean we track a selection of small public companies under a 100 million market cap. And we track them based on what their highs were in 2008 versus what they are trading at today. And we are probably in the top ten percent if not more of – while we had a lot of decrease from our high, our decrease was less than probably 80% of 905 of the companies we track. And what that tells us – what it says to us, the market, even though we’ve got a fairly small market float and trading volume, the market sees that we are still a player. And our peer groups and the companies that are similar to us also know that. We don’t have all that expensive debt these people have. We don’t have a debt that’s in excess of our proved reserve. We don’t have a lot of the characteristics that the other companies are experiencing. And so they are looking – all those companies are looking for lifeline somewhere. And it could be anywhere from additional capital to mergers to sale of assets and so they are going to come in a lot of different forms. But we are looking at every lifeline that’s thrown out there to see if there is something that will intrigue us.

David Vanture

Well, that’s real helpful. It sound like just by increasing what you have and reworking it that’s going to add substantial value to the Company and the big kicker might be that you would be able to pull off a plum from one of these opportunities, which you just mentioned. I mean that might be the biggest opportunity of the year.

Richard Dole

Yes. I think there are going to be some great opportunities. So – but it’s just early.

David Vanture

No, I understand. Alright, well thanks very much.

Operator

Our next question is from Pat McLaughlin [ph].

Pat McLaughlin

Hello.

Richard Dole

Yes.

Pat McLaughlin

Yes, Dick, this Pat McLaughlin. Just in reference to your previous comment concerning the differentiation on how Double Eagle is traded versus the small cap universe I might suggest that that be as much a reflection on your balance sheet as it is on your business opportunities. And my question relates to that. If we make an assumption I mean a lot of people are very sanguine on long term gas pricing. If we make an assumption that the spot market is in or around $4 for the next three years, I mean obviously you can hedge out and hopefully do better than that in the total mix variance for the firm, but can we continue to grow reserves without levering the Company? I mean we just got an extended and enlarged line of credit, but can we continue to grow with – in a manner that actually has the reserves free to the common shareholder versus the debt creation to get there. I mean are we literally just buying time and floating through and hoping for price movement to salvage this or can we operate at $4 and add reserves without getting too levered. That’s a lot question –

Steve Degenfelder

Yes I think I understand it and to tell you that I know the – we have not modeled your question.

Pat McLaughlin

Alright.

Steve Degenfelder

But I will tell you that we make money at $4. Our revolving credit line is cost of capital for me it is very attractive. We think that we can pretty well manage over the next few years from the cash flow and our intent is to grow reserves, but part of the problem in growing the reserve is getting the reserve engineers to understand that we are a production based asset, not a volumetric based asset. So, relevant production I think is from the existing asset portfolio with the cash flows and the credit facility we have is something we think is entirely possible. Convincing the reserve engineers to take a realistic view of the production profile is something that we’ll be working on in the next year.

Pat McLaughlin

Okay. You know I don’t know if that answers it, but that’s certainly a stab at it and maybe offline instead of just tying you up for a long time here. I’d like to just give you a buzz and kind of go over some of my thoughts on it.

Steve Degenfelder

Sure.

Pat McLaughlin

Alright.

Operator

There are no more questions.

Richard Dole

Okay. If there is no other questions, thank you all for attending and thank you for the questions. And hopefully we did as good – well we did as good as we could in answering them, maybe we didn’t answer them all. So, thank you and have a good day.

Operator

Ladies and gentlemen, this will conclude our conference. Thank you for joining us today.

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Source: Double Eagle Petroleum Co. Q4 2008 Earnings Call Transcript
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