Double Eagle Petroleum (NASDAQ:DBLE)
2013 Earnings Call
March 13, 2014 11:00 am ET
Richard D. Dole - Chief Executive Officer, President and Director
Adam Fenster - Chief Financial Officer
Ladies and gentlemen, thank you for standing by. Welcome to the year-end financial results and operations update conference call. [Operator Instructions] As a reminder, this conference call is being recorded. I would now like to turn the conference call over to your host for today, Richard Dole, Richard, please go ahead.
Richard D. Dole
Thank you. Good morning, everyone. I'd like to welcome you to our call to discuss our year-end 2013 financial results, and give you a brief update on the current activity at Double Eagle. Joining me today is our new Chief Financial Officer, Adam Fenster. Adam will begin by providing an overview of our 2013 financial results. And afterwards, I will provide you an update on our drilling and exploration projects. With that, I will turn it over to Adam.
Thank you, Dick. Before we continue, I'd like to point out that all statements made during this 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. Actual results could vary materially from those contained in any 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 reports on Forms 10-K and 10-Q, as well as in our press releases.
For the year ended December 31, 2013, we realized a 2.6% decrease in revenue from the sale of Oil & Gas. Our 2013 revenue, which includes realized hedging activities, was $37.9 million as compared to revenue of $38.9 million in 2012. This change was the result of a decrease of 12.4% in our year-over-year production volumes, offset in part by an increase in our net realized natural gas prices of 11.5% with our realized hedges.
Our 2013 total net production was 9.2 billion cubic feet equivalent or Bcfe compared to 2012 production of 10.5 Bcfe. The year-over-year drop in production was primarily the result of decreases at our Catalina Unit, and to a lesser extent, decreases in our nonoperated Spyglass Hill and Mesa units.
As reported on our prior 2013 calls, we experienced compressor failure and injection issues at Catalina in 2013. Our operations team worked to address these issues, and along with the third quarter work-over program which focused on the Almond formation, Catalina saw a sequential increase in production of 9% during the fourth quarter versus the third quarter.
Production decreases experienced from our non-operated wells were primarily the result of a change in operators completed in 2013, and the deferral of maintenance on various wells. We believe that the operator has addressed these issues and we expect to see improved production from these wells moving forward.
As far as our net realized natural gas pricing is concerned, we saw an increase from $3.70 per Mcf in 2012 to $4.12 per Mcf in 2013. We benefited from increases in spot Colorado Interstate Gas index pricing in 2013 versus the prior year, and continued to realize gains on settlements from our hedging activities.
For 2013, we reported a net loss attributable to common stock of $16.8 million, versus a net loss of $14.1 million in 2012. On a per-share basis, this translated into a loss of $1.48 per share in 2013 as compared with a loss of $1.25 per share in the prior year. Our 2013 results included non-cash losses related to the changes in fair values of our economic hedges of $6.7 million, versus non-cash losses of $7.9 million in the prior year. Our cash gains on settled hedges were $6.2 million in 2013.
One more non-cash item of note. During 2013, we recorded an additional impairment of $4.8 million, associated with our Niobrara exploration well. Our Niobrara well is currently producing natural gas. However, we no longer expect -- we expect oil recovery from the well. We have submitted an application for a permit to allow for well production from the Frontier and Dakota formations. We expect to receive this permit by the summer and we will begin production from these formations once Wyoming's wildlife stipulation period ends in August.
We reported clean earnings income of $10.2 million in 2013 versus income of $15.2 million in the prior year. For a definition of clean earnings, please refer to yesterday's press release. Our year-over-year decrease of 33% in clean earnings was primarily related to lower production volumes, increased production costs and taxes, both of which were offset in part by higher net realized natural gas prices. A reconciliation of clean earnings to GAAP net loss is also included in yesterday's press release.
As we discussed in our third quarter call, we continue to manage our spending to stay within the cash flow generated by our operations. During 2013, cash flow provided by operations was $13.1 million, cash flow used in investing activities was $10.5 million, and cash flow used in financing activities was $3.8 million.
With respect to our year-end reserves, our SEC year-end 2013 proved reserves were 74.7 Bcfe, which was a slight decrease from year-end 2012 reserves of 78.1 Bcfe. Decreases in our proved reserves resulting from our 2013 production were offset in part by increases in revisions, and extensions and discoveries. As a result of increasing natural gas prices, we had positive revisions of approximately 4.2 Bcfe in proved reserves, as calculated in accordance with SEC rules. With several of our proved undeveloped locations becoming economic again in 2013.
Our 2013 extensions and discoveries provided another 1.5 Bcfe of proved reserves. The increase in our -- in natural gas prices contributed to a 34% increase in the PV-10 value of our proved reserves, which increased from $58.2 million in 2012 to $78.2 million in 2013. Yesterday's press release included a summary of our reserves using forward strip pricing as of year-end 2013. When calculating the value of our reserves using forward strip pricing, our proved reserves totaled 91.9 Bcfe with a PV-10 value of $99.4 million.
With that, I'll turn the call back over to Dick to provide an update on our drilling and exploration activities.
Richard D. Dole
Thanks, Adam. I'd like to begin with an update on the drilling activities. In the company's Atlantic Rim acreage, drilling activities are primarily occurring in the Spyglass Hill unit. In 2013, we participated in 27 wells in the Doty Mountain participating area, or PA as I'll refer to it going forward, within Spyglass Hill, at an average working interest share of cost of approximately 11.7%. Our adjusted PA net revenue interest is just under 20%. So we will see a nice pick up in the participation of the production in the reserves that are associated with those wells. Production from those wells began in 2014.
Warren Resources, the operator in the Spyglass Hill unit, just announced the 214 [ph] development plans, which include the drilling of 48 wells within Spyglass Hill, which will satisfy the unit's drilling requirement through 2015. We are awaiting specifics on well locations, but we expect several of the wells will be in the Sun Dog PA, which will be able -- which we will be able to participate in to the extent that they are located on our leases. For wells drilled on our leases, thus far in the unit, we typically have a working interest cost that range from 10% to 12%. And depending on how many of the 48 wells we will be participating in, we expect to participate on an adjusted estimated net revenue interest basis, somewhere between 14% and 16%. We'll provide exact figures relative to our participation in these 48 wells once we know which wells are located on our lease.
Also, Warren announced its plan to drill 6 injection wells to provide for a more efficient dewatering of current and future wells in order to accelerate production growth. Beyond the drilling of this 48 wells slated for 2014, Spy Hill Glass -- Spyglass Hill offers extensive development opportunities, with 175 drilling locations, 400 possible additional drilling locations, and 60 possible recompletion opportunities from drilled wells that have not yet been fractured, stimulated and are presently shut in. These future opportunities were all presented by the operator, based on the review of the previous operator's, well logs and historical production volumes. We have approximately 10 additional locations in the Catalina Unit, but to drill those required -- requires Warren Resources' approval, and they have not agreed to drill the locations as of yet.
Moving on to our acreage on the Pinedale Anticline, in 2013, we participated in 11 wells, which were located in Mesa "B" PA. With the additional wells drilled -- with an additional well drilled in 2014, the Mesa "B" PA is now fully drilled out, and future drilling activities there will move to Mesa "A" and Mesa "C" PAs. Double Eagle has a 0.3% overriding royalty interest in the Mesa "A" PA, which we expect drilling to commence this year. In the Mesa "C" PA, we have approximately 9% average reversionary carried interest. And we expect drilling to commence there beginning in 2016. We will not need to contribute any capital for the activities in either of these PAs, but we will participate in the production and reserve additions for any new wells.
As far as our undeveloped acreage is concerned, we are seeing some very positive activities in and around some of our significant lease holdings. In the Washakie Basin, south of our Niobrara acreage, 3 Niobrara wells are planned for drilling this year by GRMR, Oil and Gas, LLC, which is an affiliate of East Resources, Inc. They will be shooting seismic and 3 wells are planned as horizontal wells, which could be the first wells of this type targeting the Niobrara formation in Carbon County, Wyoming. Double Eagle has about 40,000 net acres in the Washakie Basin, and activities focusing on the Niobrara formation continue to move closer to us.
Just last week, Southwest Energy Co.'s announced their acquisition of over 300,000 net acres south of -- in Northeast Colorado. Their focus being on the Niobrara formation. In the nearby Hanna Basin, drilling is expected later this year, with seismic having already been shot, and drilling expected to target the Niobrara formation, as well as other conventional zones. We have 12,300 net acres and 22 -- over 22,800 gross acres in the Hanna Basin, and we'll be paying close attention to the drilling results as they become available from the operator.
Finally, we're very excited about what is developing on and around our Huntington Valley acreage in Elko County, Nevada. Noble Energy has leased over 300,000 net acres in northeast Nevada, including acreage in Elko County, where we have approximately 6,100 net acres over a 22,500-acre gross footprint. Plus we have overriding royalties on that acreage that vary from 2% to 5%. We received notification of Noble's plans to form 2 federal exploratory units, one of which would include several of our leases. Noble has 3D seismic for most of the proposed unit area, and they are currently evaluating potential drilling sites. Their proposed federal exploratory units are subject to approval by the Bureau of Land Management, so we are anxiously awaiting BLM's response.
As you can see, we have new reserves being generated over the next several years in Pinedale and the Atlantic Rim with minimal capital requirements. Pinedale and the Atlantic Rim, began development in late 2007, and through the next 6 years, we deployed about $170 million of capital into those 2 fields, which included the participation in approximately 400 wells between those 2 fields. After 6 years of production, we have an estimated $290 million of future cash flows remaining after capital on operating costs on those assets.
In 2013, as drilling activity declined in the Catalina Unit and the Mesa units, drilling moved to areas where we have no capital requirement. The company began focusing on creating new projects for the future. Approximately 6 months ago, we began building networks within the industry, and within the capital markets, relative to creating new significant projects and attracting new talent for execution on these opportunities. These activities are targeted to warrant -- allowing the company to start providing additional significant incremental growth during 2014.
And with that, I'll open the call up to questions.
[Operator Instructions] Our first question comes from Richard Dearnley with Longport Partners.
Good morning. Could you talk more about the new people you've added and the targets you're contemplating? And what investments you've spent so far in that regard?
Richard D. Dole
Well, we have minimal investments. We've been creating the network, we are getting deal flow, we're looking at projects that are -- some conventional and some not so conventional. There's nothing that we can talk about now, specifically as -- to people, because we've not hired or brought on the people. But a lot of them are more along partnering relationships. The projects are in very early stage and we're doing some due diligence on several of them. As I mentioned, some conventional-type acquisitions and some other projects that are less conventional. But, it will take us a few months to get those finalized and focused, and hopefully, we'll be able to announce some interesting opportunities as the year goes forward.
Right. And how would you finance an investment of that nature?
Richard D. Dole
Well, there's a variety of ways. We've had a lot of interest in institutional, meaning, companies who are trying to gain access to U.S. assets, some abroad, and some in the United States. So there's a lot of capital available, it's a matter of getting the right project to finance around. And then, of course, any project that is a significant project, that has significant value, is always a financiable transaction.
[Operator Instructions] Our next question comes from George Britton [ph] with Britton Investments.
Could you give me the breakdown for your PV -- your NPV-10 using your strip pricing, and break it down for your proved reserves, and your -- for your developed and undeveloped and probable? Could you provide those numbers?
Richard D. Dole
Yes, basically, the proved developed is approximately 60% to 61% of our total proved reserves.
You gave that number, what that number is?
It's $58 million. And then the remaining...
Is that the SEC pricing?
That's the strip pricing. And the remainder is our PUDs.
The reminder are proved undeveloped.
Okay. So, the total was what? The total proved reserves, NPV-10 with strip pricing?
Strip pricing, the total was $99.4 million.
That was for the proved?
That's the total proved. Correct.
And what was probable?
Probable, I don’t have in front of me. I can get that to you supplementally.
Was that down from last year, which was $162.7 million?
It was. And our hedges at the end of the 2012 were more favorable than our hedges at the end of 2013, which is the primary driver there.
Richard D. Dole
Oh, there are no more questions. I'd like to thank you all for attending. And, of course, you can always follow-up with questions directly to Adam, if you think of something after the call. Thank you, again. Have a good day.
Ladies and gentlemen, this will conclude our conference. Thank you for joining us today.
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