ZaZa Energy's CEO Discusses F4Q12 Results - Earnings Call Transcript

Apr. 2.13 | About: ZaZa Energy (ZAZA)

ZaZa Energy Corporation (NASDAQ:ZAZA)

F4Q12 Earnings Conference Call

April 2, 2013 10:00 a.m. ET

Executives

Jay Morakis - Investor Relations, JMR Worldwide

Todd Brooks - President & Chief Executive Officer

Ian Fay - Chief Financial Officer

Kevin Schepel - Executive Vice President, Exploration & Production

Thomas Bowman - Executive Vice President, Evaluation, Geology & Geophysics

Analysts

Chris McDougall - Westlake Securities

Brian Kabot - Riverloft Capital

Richard Dearnley - Longport Partners

Robert Kecseg - Las Colinas Capital Management

Chris Cook - Zazove Associates

Mitchell Metzman - Metzman Capital

Unidentified Analyst

Pat McLaughlin - UBS

Operator

Good day, ladies and gentlemen, and welcome to the 2012 yearend ZaZa Energy earnings conference call. My name is Derrick and I’ll be your operator for today. At this time all participants are in a listen-only mode. We shall facilitate a question-and-answer session at the end of the conference. (Operator Instructions). As a reminder this conference is being recorded for replay purposes.

I would now like to turn the conference over to Jay Morakis of Investor Relations. Please proceed.

Jay Morakis

Thank you, Derrick. Good morning and welcome to ZaZa Energy Corporation’s 2012 yearend conference call. Today’s call is being webcast on our website www.zazaenergy.com and can be accessed in the Investor Relations section. With me this morning are Todd Brooks, President & Chief Executive Officer; Ian Fay, Chief Financial Officer; Kevin Schepel, Executive Vice President, Exploration & Production; and Thomas Bowman, Executive Vice President, Evaluation, Geology & Geophysics. All will be making remarks on today’s call after which we’ll open the call up for questions.

Before we begin, I would like to remind everyone that statements made on today’s call and webcast may contain forward-looking statements as defined by the Securities and Exchange Commission. Any statements made are subject to a number of assumptions, risks and uncertainties, many of which are beyond the company’s control and which may cause actual results to differ materially from those implied or expressed by those statements. For a full list of risk factors, please refer to our Form 10-K which was filed with Securities and Exchange Commission this morning.

At this time I’d like to turn the call over to Mr. Todd Brooks. Todd?

Todd Brooks

Good morning and thanks for joining us today. We were busy in 2012 executing a series of strategic transactions that strengthened our balance sheet and high graded our asset base. Today our focus is on developing our core resource base from which we’ll grow our production reserves and cash flow. We will also continue to divest specific Eagle Ford assets to further strengthen our financial position as we focus on the Eaglebine area for our growth.

Currently, we are flowing back the Commodore well and are testing multiple zones in the lower Cretaceous. On the Stingray well we encountered hydrocarbons in the lower part of the hole and as a result immediately ran production casing. We are now set to log it using cased hole logs. After evaluating these logs we’ll prepare for what is likely to be a multi-zone vertical completion.

We’ll come back to operations in a few moments, but first let me provide a recap of 2012. In February we completed a reverse merger with NASDAQ listed Toreador and became a public company. At the time of the merge, ZaZa had two separate joint ventures with Hess Corporation, a 10% working interest in 123,000 acres in the Eagle Ford and a 50% working interest in the Paris Basin unconventional. Both JVs had accompanying carried well components.

Within the context of the merger, we retired $34 million of existing Toreador debt and issued $100 million of new senior secured notes. A month later, in March, we initiated a joint venture with Range Resources to further supplement our Eaglebine position. Then in July of 2012 we successfully exited our joint venture with Hess. As a result of this transaction, ZaZa received $84 million in cash, approximately 61,000 additional net acres in the Eagle Ford and a 5% cost re override capped at $130 million on the unconventional assets in the Paris Basin that Hess received. The Eaglebine asset was never part of any joint venture with Hess.

We continue to be pleased with ZaZa’s value capture from the division of assets negotiation with Hess, especially given the recent sale by Hess of the Eagle Ford assets they retained for $265 million, coupled with last week’s announcement by ZaZa of the sale of 12,000 of our 72,00 acres of Eagle Ford assets we will take in the split for approximately $52 million. We estimate that ZaZa will end up capturing at least 50% of the total value from the Eagle Ford JV.

In December of 212, we divested our Paris Basin conventional assets in a transaction with Vermilion for a net sale price of approximately $76 million. Upon consummating our division of assets transaction with Hess, it became clear that the Paris Basin conventional asset was non-core. This Paris Basin conventional asset divestiture marked our official operational exit from France as we continued to streamline the company and focus on the unconventional assets in sectors.

By the end of 2012, less than 10 months after the merger, we paid down approximately $67 million of the $100 million worth of senior secured notes and we are currently in the process of bringing the notes down by another $8 million to where the senior secured principle is approximately $25 million. Later in 2013 I would expect the principal of these notes to be brought down even further as I would look for ZaZa to divest another Eagle Ford asset as we continue to strengthen our balance sheet and focus on the Eaglebine.

Regarding the Eaglebine, ZaZa is the most heavily weighted company to this play in terms of net Eaglebine acres as related to total enterprise value and much of our acreage will now be in a partnership with one of the largest and most successful unconventional oil operators in the world. Given this relatively high Eaglebine weighting, the company stands to gain relatively more than any other public company as the Eaglebine gets derisked within the JV on our offset carve out acreage and on the acreage developed by surrounding operators.

As ZaZa is the most singularly focused company in the Eaglebine area, it is important to understand that it’s not just the lower Eaglebine zone that we are looking to develop. The company is not taking single reservoir risk. We are dealing with stacked pay here. There are multiple zones for development and multiple ways to go about developing these different zones which is important from a risk diversification standpoint. We feel that ZaZa has the most respected acreage in the Eaglebine area for a variety of technical reasons which Tom and Kevin will discuss shortly.

ZaZa was the first mover in this area and we could have built our acreage block anywhere that we wanted. We spent considerable time in the evaluation of the entire prospective area and made the decision to take the acreage where we are today. We further feel that our new joint venture is a validation of the acreage we selected and the proof of concept work we’ve executed to date.

I’d like to finish by touching on the commercial points of the joint venture we announced last week. As per the terms of this JV agreement, in total our joint venture partner will receive up to 55,000 net acres and operate the JV comprising 73,000 of our 92,000 net mineral acres. The assets the JV will develop include certain lands located in Walker, Grimes, Madison, Trinity and Montgomery Counties and also incorporate certain properties that are covered within our participation agreement with Range. The remaining acreage totals 19,000 net acres. 15,000 of these acres are positioned in the center of the block adjacent to our recently drilled Discovery wells and we will retain this 100%.

As outlined in our agreement, our JV partner will serve as the operator and in total will pay us a cash of up to $50 million, carriers for the cost of drilling and completing up to nine wells and pay for up to 42.5 million of our share of any additional seismic or well cost in order to earn their interest in these properties. ZaZa will retain a 25% working interest and our JV partner will receive a 75% working interest in the acreage in which we currently own 100%, aside from the 19,000 retained 100% acres.

On the ZaZa/Range JV acreage, our JV partner will earn a 50% working interest and both ZaZa and Range will retain a 25% working interest. This JV has been structured as a three phase rollout. In the first phase we will transfer 20,000 net acres, approximately 15,000 of which will come from our JV with Range. Our JV partner will make a cash payment of $10 million to ZaZa upfront upon closing this transaction and will drill three wells by December 31, 2013 for which our JV partner will be required to pay for all the drilling and completion costs. One of these wells will be the substitute earning well we are required to drill pursuant to our agreement with Range. Early stage drilling preparations are already underway for the first two wells.

Phase 2. Within 60 days of the third well’s completion in Phase 1, our JV partner will have the option to go forward with the second phase of joint development. At this point, ZaZa will transfer an additional 20,000 net acres and our JV partner will make a cash payment of $20 million to ZaZa. Similar to Phase 1, our JV partner will be obligated to pay 100% of the drilling and completion costs for an additional three wells, which makes six carried wells in total through the first two phases and up to $1.25 million to ZaZa share of any additional seismic or well costs. Then as we move into Phase 3, the same terms and conditions apply as to Phase 2, although in Phase 3 we’ll be transferring 15,000 net acres as opposed to 20.

We also carved out 15,000 wholly owned acres in the middle of the block. Curving out this strategic asset accomplishes two ends. It allows ZaZa autonomy and control in the sense that the company is not beholden as a non-op to our JV partner’s development pace and it gives ZaZa the opportunity to further capitalize on the value increase of the 100% acreage position as the JV develops and proves up the acreage surrounding it.

It is our intention to begin developing our 100% owned and operated acreage once the JV has moved up the learning curve and we are confident in the cost efficiency of our capital spend. The JV is currently learning from the work that ZaZa has already done in the area. Moving forward, during 2013 as the JV derisks and develops the acreage, our CapEx and G&A costs associated with drilling are expected to be significantly reduced this year as compared to last.

With this joint venture and the Eagle Ford sale we announced last week, we are fully funded through 2013. As the JV moves forward, we have up to nine sequentially carried wells in the Eaglebine and we are planning to establish a reserve base lending facility later this year. We’ve been presented with other non-dilutive financing options should the need arise to fund cash costs from our new JV partner among other uses and we are currently evaluating each option carefully.

We will continue to divest select Eagle Ford assets as we high grade our acreage position with a focus on the Eaglebine. We do not anticipate any dilutive transactions in 2013 or 2014. The focus is on developing the Eaglebine within the JV and as a standalone project independent of the JV. We will run parallel tracks. We always remain opportunistic and if the right production acquisition came along we would take a hard look at it.

Tom and Kevin will now provide a technical and operational review before handing over the call to Ian who will go through the financial results, then we’ll have a few minutes for questions. Tom, Kevin?

Kevin Schepel

Thanks Todd and good morning to everyone on the call. This is Kevin Schepel. We’d like to start out with technical and operational review of our recent activity and our current view of the Eaglebine play based on the data acquired from our proof of concept wells drilled in 2012. After doing that we’d like to talk a little bit about the increasing industry activity in lower Cretaceous, our Eagle Ford expansion at Sweet Home and then briefly discuss the status of our remaining Eagle Ford assets. Please note that we’ll provide more technical detail and additional illustration in our upcoming investor conference materials.

Let’s talk a little bit about the Eaglebine. It’s important to note that Eaglebine is quite different from Eagle Ford and it has its own set of technical and operational challenges. It’s also important to point out there are multiple producing horizons in the play, one of which is the Eaglebine shale, many operators are focusing on the deltaic sands of the Woodbine group as they terminate into these basinal shales. ZaZa’s position has been compared to some of these operators, but the fact our position in the play is quite distinct and different. We are focused on the most organic rich interbedded limes and silts in the thickest portion of the basin just above the Buda formation. This is the most analogous to the Eagle Ford and contains the kerogens needed for higher liquid yields at these depths.

The interval is distinct and different from the Woodbine Sand Play and we feel offer significantly higher upside and productivity in reserves. ZaZa’s first three wells, the Commodore and the Stingray horizontal and vertical were designed to gather information needed to evaluate the multiple reservoir targets in the upper and lower Cretaceous, including the Eaglebine to confirm commercial reality and focus on the best combined development strategy.

Operationally, drilling and completing the Eaglebine has been a challenge. Many operators have jumped into the play applying the same drilling and completion techniques as in the Eagle Ford and they have not had favorable results. We have had our share of operational challenges as well, but we are learning quickly and gathering essential data moving forward. Our first proof of concept well, the Stingray A-1H, was a technical success and the data confirmed our early prognosis of the play. While drilling, we encountered liquid rich mud log shows through the entire lateral section. The logs in the rotary cores confirmed the presence of organic rich shales with significant reserve potential.

The Schlumberger ELAN analysis tool showed an estimated 21 BCFs and 29 million barrels per section in place, or approximately 980,000 BOE recoverable. This was applying a recovery factor of 18% to 20%. The initial completion and the planned highway frac designed was also successful. After completion of the hydraulic fracturing operations, the casing under normal operating conditions suffered a casing collar failure which ZaZa determined had caused a down hole restriction in the lateral portion of the well. Metallurgical testing performed on the collar indicated that the collar failed because of embrittlement. So notwithstanding multiple attempts, the company was unable to remedy the restriction and the lateral was lost. The Stingray proof of concept well provided the company important data as it continues to technically prove up the lower Eaglebine in Northern Walker County.

During the short flow back of one fractured interval above the casing restriction, we recovered gas and 45.83 API gravity crude as per our Fesco fluid analysis. So what have we learned about the Eagle Ford, what’s different about it? The organic shale section is 400 to 500 feet thick in the ZaZa acreage position. This is three orders of magnitude thicker than the Eagle Ford. As a result, the effective stress is much higher which requires controlled stability and higher mud weights while drilling to offset the abundant hydrocarbon shows and ensure formation integrity. Most operators have had problems drilling the section with water based muds which leads to poor well bore conditions and problems with wire line logging running casing in the completions.

The well bore integrity problem becomes even more severe when drilling the horizontal well. We use oil-based mud in our proof of concept well to ensure that we acquire the formation evaluation and rock data we need to aid in drilling the lateral and for our completion design. We feel the advanced technical information we have obtained to date, together with our first phase of drilling commitments with our new partner, will unlock the potential of the Eaglebine. Having a proven unconventional partner in this venture and learning together will lead to establishing the best drilling and completion practices for the Eaglebine.

So since the initial drilling of the Stingray Eaglebine test, the well has now been reentered and drilled to the lower cretaceous below the lower Eaglebine and we are attempting to complete a vertical comingled well. This is the second lower cretaceous completion for ZaZa in the area and we are very excited about the results to date. We also have a very high level of industry activity in the play.

So we’d now like to provide some technical detail on that portion of the portfolio. Tom?

Thomas Bowman

Thanks Kevin. Good morning everyone. This is Tom Bowman. Let’s talk a little bit about the lower cretaceous. The lower cretaceous fractured carbonate play, currently referred to as the Buda Rose play. It contains Buda, Georgetown, Kiamichi, Edwards, Paluxy and Glen Rose formations. These reservoirs are drilled and completed in vertical wells between 10 and 12,500 feet across the ZaZa acreage position. Then they’re perforated fracture stimulated and commingled for production.

Recent rulings by the Railroad Commission of Texas have allowed for commingling in the Buda Rose formations in the Fort Trinidad area of Texas. The primary reservoir characteristics and the main objectives are a combination of fracture porosity, matrix porosity and permeability. The matrix porosity averages approximately 4% and the permeability is less than a 10th of a millidarcy. Both are ideal for modern drilling and completion techniques.

We’ve drilled two wells to the Glen Rose formation. They’re Commodore and the Stingray reentry. We are pleased to report that both wells were successfully drilled to the top of the Glen Rose and both wells had good mud log shows while drilling. Currently the Commodore has been completed in the lower formations of the Buda Rose play, with completions in the Glen Rose, the Paluxy and the Edwards. We’re currently testing these lower formations to gather data needed for the commingling permit with the Railroad Commission and we’ll be assessing the results before determining whether additional formations will be perforated and simulated.

Current restricted rates on the Commodore are approximately 500 MCF of gas, 15 barrels of oil and 650 barrels of water while initial testing and flow back. We are currently flowing the gas and monitoring the well as the well continues to clean up the stimulation fluid. We have reached TD on the Stingray reentry well and we’ll be running cased hole logs in the next few days and we’ll begin our fracture stimulations in April after we evaluate the logs and designed our custom completion program.

So let’s move over to the Eagle Ford expansion areas we call Sweet Home. As previously announced, the company’s Boening A-1H well located in DeWitt County, Texas has been drilled and tested with favorable results. The Boening well was drilled for a total measured depth of 18,797 feet and had a 5,163 foot effective lateral section which was hydraulically fractured. Seven of the 16 blow through plugs were drilled out using coiled tubing. Under controlled flow back, the initial production rate was approximately 669 barrels of oil equivalent per day or 264 barrels of oil and 2,434 MCF of natural gas on a 1260 force inch choke were achieved.

From the four point test analysis, an absolute open flow rate of approximately 1,020 barrel oil equivalent per day or 420 barrels of oil and 3.6 MMCF of natural gas were calculated. On March 17, 2013 the company elected to put the well on production. The controlled flow rate as of March 27, 2013 was approximately 138 barrels of oil per day and 324 MCF of gas.

The Boening results are encouraging for ZaZa and may open up a whole new expansion for the area. It confirms a high liquid yield reservoir interval and is the first test in this low resistivity organic part of the Eagle Ford shale which is very similar in composition to the Eaglebine. When drilling the pilot for the Boening, we acquired conventional core and some of the most advanced logging suites available. When we then completed custom petro physics designed through detailed integration of the physical rock and fluid analysis to confirm that it was a change in reservoir composition that was affecting the resistivity or more importantly, it was reservoir conductivity that was the change. Resistivity in the completed section was less than 5 ohms.

We made well below what most people use as a cutoff in the traditional Eagle Ford. This area is also previously thought to be dry gas. Importantly, we have confirmed that the organic kerogens in the shales retaining heavier liquid rich hydrocarbons which we released during the production. The GOR for the Boening has been running less than 2,500. From an acreage standpoint, ZaZa has recently high graded this Eagle Ford suite home acreage into 12 Q1 development units and expects to further delineate the Sweet Home area in 2013.

As far as the remaining Eagle Ford assets, we continue to monitor and evaluate all of our remaining Eagle Ford and Edwards assets. This includes the Hackberry and the Oakland positions east of Sweet Home. The Boening well results could greatly influence the outlook for these areas and add potential as Eagle Ford expands behind and in front of the Edwards shelf edge. In these areas the Eagle Ford is broken up into an upper and lower zones. In the upper section offering a chalky component, sometimes referred to as the [Chalkford] and the lower being a thinner, organically rich section of the Eagle Ford shale.

The existing Edwards formation also has significant development potential and we continue to monitor gas prices for commerciality. Recent industry activity in the immediate area includes leasing propositions in the emerging Midway Navarro trend and we are currently working on a full technical assessment. We look forward to providing ongoing technical and operational updates as we move into the next phase of the company’s growth and evolution.

At this time I’d like to turn it over to Ian Fay for our financial review.

Ian Fay

Thanks Kevin. Good morning everyone. I’ll echo Todd’s sentiments that the past year has been quite busy, very productive and in many ways transformational. The strategy we put in place last year as the exit with Hess took form is now starting to bear fruit and we’re very comfortable with our current marketing position, our remaining asset base, our improved liquidity position and most importantly, our future.

Please keep in mind that as I review the highlights of our 2012 annual report that our results of operations include the results of ZaZa LLC, the formerly private company from January 1, 2012 to February 20, 2012 and then all of our subsidiaries since February 21, 2012 through December 31, 2012. However, these results exclude ZaZa Energy France which we sold on December 21, 2012 and is presented as a discontinued operation in our 10-K. Throughout my remarks I will provide details on the transactions Todd outlined and cover the impact that all of them have on our financial statements.

So to begin. We reported full year 2012 revenues of $205.2 million, which includes $195.6 million related to the gain on the termination of the Hess agreement. Other income from the Hess transaction primarily consisted of the following three pieces. There was a step up to share value for our oil and gas properties of $117 million, a write-off of $5.4 million in working capital and a total cash amount paid by Hess to ZaZa of $84 million.

Oil and gas revenue for 2012 was $9.6 million, up $7.1 from $2.5 million we reported in 2011. Our revenue production increased despite the developed properties we divested throughout the calendar year and this increase we posted year over year is primarily due to the increased production in the U.S as we had a handful of new wells coming online along with the increased net revenue interest received as a result of the termination of the Hess agreement. We also all enjoyed an increasing oil prices over the comparable period.

Total operating costs and expenses for the year ended December 31, 2012 were $130.9 million. That’s compared to $20 million in the 2011 period. Within this, the most significant increase was in general and administrative expenses, which were $97.9 million versus an $18.1 million for 2012 over 2011 respectively.

The G&A increase was due primarily to higher legal and advisory fees as well as payments to the executive founders pursuant to the combination of ZaZa LLC and Toreador which was consummated in February 2012. The increase is also related to stock compensation expenses of approximately $15.5 million in 2012, a tax reimbursement to the founders of $4.1 million, increased employee benefits severance changes and increase rental costs. Overall, the Toreador entity contributed $14.4 million of this G&A throughout 2012.

We also had an increase in lease operating expenses which were $3.6 million or $28.90 per BOE produced in 2012, versus $1 million or $34.91 per BOE produced in 2011. In 2012, incurred exploration expenses of $12.9 million related to our horizontal drilling of the Stingray A-1H well which was mentioned prior versus no expenses of this kind in 2011.

Additionally, we had $6.6 million of depreciation, depletion and amortization versus $900,000 in the prior year. This increase was primarily due to the step of our oil properties associated with the termination of agreements with Hess. In addition, we recorded an impairment of oil and gas properties of $9.8 million in 2012.

Our oil and gas properties with a carrying value of $59.2 million were written down to their fair value of $51.7 million, resulting in a pretax impairment charge of approximately $7.5 million. In addition, expiring leases with a combined book value of $2.3 million were also written off.

Further, we reported operating income of $74.3 million in 2012, versus an operating loss of $2.5 million in 2011. In 2012 total other expenses were $45.4 million as compared to $264,000 in 2011. This expense of other expenses of $45.4 million in 2012 was comprised of the following three categories.

One, the loss we recorded on the extinguishment of our debt as we made aggregate principle payments of $66.8 million from original issuance in February of 2012 through the end of the year in 2012, reducing our debt on our senior secured notes by approximately two thirds. This loss on debt extinguishment consists of $5.2 million in fees paid in connection with the prepayment and $22.8 million due to the write off of issuance cost and original issued discounts related to the $100 million original issuance at the time of the combination.

Second piece of this was net interest expense of approximately $14.7 million and finally, we recorded a gain in fair value of the warrants associated with our senior secured notes of $5.6 million and a loss in fair value of embedded derivatives associated with our convertible senior notes of $8.2 million. These variances are mainly a result of fluctuations in our stock price since the initial valuation issuance which was in October of 2012 for the converter.

Pretax income from continuing operations was $28.9 million in 2012 versus a pretax loss of $2.7 million in 2011. Further, in 2012 we recorded an income tax expense of $82.9 million, which has resulted in a loss from continuing operations of $54 million. That $82.9 million of tax expense was primarily due to a significant amount of repatriation, steam dividends and valuation and allowances. Please note that in 2011 we had a minimal pickup in income tax expense of $123,000 which was the result of the Texas Margin Tax.

Finally, we reported a $52.2 million loss from discontinued operations, net of income taxes, resulting in a 2012 net loss of $106.2 million, or a net loss of $1.08 per share basic and $1.11 per share basic fully diluted in 2012 versus a net loss of $2.9 million or a net loss of $0.04 a share, both basic and fully diluted in 2011.

Now, let me move on to the balance sheet. As of December 31, 2012 we had cash and cash equivalent for a total of $34.6 million as well as restricted cash of $21.9 million. That $21.9 million of restricted cash was comprised of $15 million held back in an Escrow as the result of our Hess transactions and $6.9 million which is a hold back related to the sale of our Paris conventional at the end of 2012. This compares to cash and cash equivalents of $10.6 million and restricted cash of $111,000 at the end of December, 2011.

Also, at the end of December 31, 2012 our long term debt net of discount was $96.3 million. This consisting principle amount of $47.3 million of subordinated notes, $23.6 million of the senior secured notes net of discount, that discount being approximately $9.6 million and $25.3 million of our convertible senior notes net of discount and that discount is about $14.7 million.

I’d like to now provide some background on the financial transactions we entered into in 2012. In February as I mentioned prior in connection with the Toreador combination, we issued senior secured notes with a principal amount of $100 million which mature in 2017 through a private placement. As a result of prepayments primarily in connection with the dissolution of our Hess joint venture as well as the sale of our Paris Basin conventional assets, we reduced the outstanding principal amount of the senior secured note to $33.2 million as of December 31, 2012.

In October of 2012 we completed a private placement of $40 million of 9% convertible senior notes due in 2017. Finally, on December 21, 2012 we divested of our Paris Basin conventional assets to Vermilion Energy for a total sale price of $86 million or approximately $76 million net.

So as I said at the beginning, I’ll circle back and say again, needless to say we had a very busy 2012. Let me move now to our recently announced transactions we’re very excited about. Upon the closing of these three deals we announced last week, we estimate we’ll have an additional $60 million in cash to do several things. One, provide some liquidity for our ongoing development program. Two, continue to pay down our debt and three for general corporate purposes. In other words we’ll be positioned from a liquidity standpoint to build out our remaining assets and potentially acquire other properties in Texas and or other areas in the U.S as Todd mentioned earlier. This positioning allows us to continue to play to our strengths and the evaluation and execution of proof of concept strategy regarding pre emerging unconventional plays in the U.S primarily.

In addition, we also have $15 million held in Escrow as a carryover from the termination of the Hess agreements as part of our restricted cash that I mentioned earlier. This $15 million will be released to ZaZa when all the Paris Basin exploration permits are successfully transferred to Hess. We expect that to happen or to have happened before 12 months from today.

Related to our Paris Basin divestiture, an additional $6.9 million as I mentioned before has been earmarked and included in restricted cash for the wind up of activities there, including French capital gains tax and some severance fees.

Now, moving on further into 2013. While our proven reserves will be down given the transaction we disclosed last week related to the sale of Moulton assets as well as the JV in Eaglebine, we still maintained 100% ownership as mentioned before of approximately 19,000 net acres of highly attractive land assets in the Eaglebine. As well as an approximately 34,000 net acre position. This was at December 31, 2012 in what we call our Sweet Home prospect which is highly prospective and located in Eagle Ford. As I noted prior, we’ll be using these proceeds from the transactions to continue to pay down our debt and to drill wells, pay for land leases that are core and for potential acquisitions and or further partnerships.

Let me now move to our plan for the balance of 2013 and beyond. We’ve put in place a detailed budget for 2013 that significantly reduces our capital expenditure requirement for the year. this plan was jumpstarted just last week by the announcement and moving forth the close of both the JV and Eaglebine and the sale of Moulton assets. Our plan includes that beginning by May of this year, we will implement a plan to reduce our G&A burden by a goal of 25% to 35% across the board.

As we move further into 2013 and begin to fully appreciate the pace and requirements of our Eaglebine development program with our partner, as well as further clarify the alternatives available regarding our remaining Eagle Ford assets, we will then refocus on selectively hiring and a strategy for a dramatic recalibration of our team with a goal of positioning ZaZa for the balance of 2013 and beyond. In the near term, we will be operating lean, but at the same time we will continue to be opportunistic.

In conclusion, we’re all very excited about our current positioning, our focus on the transformation we have initiated. We’re prepared for the work to be done for the balance of 2013 and most of all ,ready to move into the next phase of the company’s success. Look forward to speaking with you all in future quarters and hopefully meeting you very soon at conferences and while we’re on the road.

I’ll pass the call back to Todd now for some closing remarks and thank you. Todd?

Todd Brooks

Thanks Ian. With last week’s announced transactions, it is clear that 2013 will be just as busy as 2012 for us. This year however we get to focus on growing our production reserves and cash flow in the Eaglebine, alongside a large best in class oil focused operator. I look forward to providing continued operational updates as the company derisks the Eaglebine, both inside the JV and as a standalone.

With that, operator, I’d like to open up the call for questions if there are any.

Operator

Question-and-Answer Session

(Operator Instructions). And our first question will be coming from the line of Chris McDougall from Westlake Securities.

Chris McDougall - Westlake Securities

Thanks for taking the question. You mentioned looking for further unconventional assets to acquire in the future. I'd love to understand your screening process and due diligence process for those and what types of things are you looking at as far as size and maturity and such?

Todd Brooks

Sure. Tom, Kevin, you guys want to talk about our screening process a little bit and the due diligence associated with new ventures?

Thomas Bowman

First, let me tell you that ZaZa with the experience that we have, we’ve always been looking for new shale plays and we’re always pushing the edge. I think as Kevin and my experience and our staff we’ve probably been involved in every shale play in the United States at some point in our careers. So we continue to use those shale plays as one of our in comparison plays as you will, but for ZaZa to enter into a completely new shale play, there’s got to be several factors that are going to have to be met and a lot of that is done with our own internal petro physics section. I think Kevin will talk a little bit about that.

Kevin Schepel

I think it’s important to look back at our history guys. We drilled what, 30 wells initially. It took over 4,000 foot a conventional core, 700 rotary sidewall cores and we had an extensive database to basically use as integration with our open hole logs and our petro physics to help us evaluate plays, look at production response in the existing plays and use those as analogies to move out into new areas and that’s the most important. Tom and I we’ve been very busy focusing obviously on our activity, our operations. We’re looking forward to this year I think it’s a good opportunity for us to step us out of the box and actually start looking at the new plays. And we’ve already have several of them we’ve already been evaluating. So I think Tom and I are looking forward to it as all the guys that are wrong with us. So start moving forward, looking for the next new year.

Chris McDougall - Westlake Securities

Okay, great. So I get the impression that you would be looking for ones that aren't the well-known, heavily trafficked plays,. You would be looking for a little bit earlier stage and maybe higher kind of risk return type opportunities. Is that a fair assessment?

Kevin Schepel

Yeah. I think -- actually we recently had some articles that we discussed this. If we all made the same maps and looked at the same data, we’d all be competing for the same exact area. But one thing that we’re very keen on is that we like to be a fast mover. We like to evaluate, get out of the box. We like to look at where the existing plays go, where it expands and we typically can get into those areas at a lower cost, multi-leasing and just not having to compete on the land side with the competition. Now that’s not to say we wouldn’t get into an emerging play if the conditions were right, but we tend to like to be fast movers in new areas. And we think we have the technical capability and technical staff to evaluate those.

Operator

Your next question will be coming from the line of Brian Kabot, Riverloft Capital.

Brian Kabot - Riverloft Capital

Actually wanted to ask the ops guys about what they are seeing in the lower Cretaceous. I know that we have some preliminary data from the Commodore, but would love to know what they are seeing or hearing from other wells in close proximity like the one drilled by Navidad.

Todd Brooks

That’s a great question. The Navidad well is about five miles, six miles north of us. It’s over the county line in Madison County. The one we really reference and Navidad is probably one of the experts out here, but there are several operators and the Port Trinidad field has produced an immense amount of hydrocarbons from various zones in the lower Cretaceous. So it’s a new play by any means. The Buda field over at say (inaudible) Buda field has produced several tens of thousands of barrels of oil. The well we look at though I think is a good example is the Navidad 9-1, Ferguson Prison Unit well. That well in 15 months has produced over 165,000 barrels of oil and only four tenths of BCF are gas which gives us that low GOR that we’re looking for in the area and that gives us a standard to compare.

Yes, it’s comingled as per the Railroad Commission, but our direct offset to us would be, maybe an example might one of the new Bluestone wells and there’s a new, just the Buda, Georgetown, Edwards well offsetting us. In fact we’re surrounded with acreage and it’s got an IP rate of roughly 450 barrels of oil per day. So we’re seeing more and more of these wells come out, but I will go back to the fact that our acreage position is sitting on the old Lola Glen Rose field. So there’s been gas production out here since the ‘80s. So it’s not a new concept. It’s just now taken a new spin being to be drilled vertically and comingled.

So any one of those zones now can be added and I think you get the combination of all of them. Remember you’re adding the Kiamichi shale and the Paluxy shale which we believe are oil rich to potentially more gas rich over carbonate. So we see a better rate return on these wells and I think there’s plenty of other operators now looking at it. Like I said Navidad being the newest, but Burk, Silver Oak, you’ve got Anadarko in this, Devon playing the lower Cretaceous. We’re seeing Cabot entered into it in Houston County. So there’s a lot of surrounding activity going on.

Kevin Schepel

I think it’s also important to note that every lower Cretaceous well we drill and evaluate, we also see the lower portion of the Eaglebine which is our secondary or sometimes primary target. So it’s important we’re getting that data constantly and it’s going to just help improve our evaluation of the area.

Brian Kabot - Riverloft Capital

And then if I can a separate question for Ian here. Ian, I've gone through the 10-K and then pro forma the cash and the debt for the JV and the sale of the Moulton acreage and I'm getting a net debt number of very close to zero. Is that -- am I on the right track there?

Ian Fay

Good question, Brian. You are. If you’re including the restricted cash in that calculation which I expect you are and the proceeds that we’ve outlined over the course of the year for the JV as well as what we’ve announced for the Moulton sale. We’re a little bit -- we’re actually near to the cash positive area when you go totally pro forma to the year

Brian Kabot - Riverloft Capital

Yes, I think I was getting like $1.5 million of net cash, somewhere in that range.

Ian Fay

That sounds very close and I think that’s -- you’ve said the same math we’ve been doing which gives a lot of comfort that we’ve got flexibility to be opportunistic as we continue through the year.

Brian Kabot - Riverloft Capital

Yes, absolutely. All right, well, thank you, guys. I'll get back in the queue.

Operator

Your next question is from the line of Richard Dearnley, Longport Partners.

Richard Dearnley - Longport Partners

Could you talk about the length of time the Boening well took and what kind of problems you had there?

Todd Brooks

Well, the Boening well initially was drilled as part of our Hess joint venture. We drilled it according and extensive parts of the well in an immense amount of analysis. That analysis alone took the better part of probably six months just to get the initial results back. So we looked at everything. Being as it was a new concept, the lower resistivity outstepped the typical Eagle Ford. We wanted to make sure that we could handle all the complications that would come from drilling it. So that put the well approximately, probably 9 or 10 months into a slide before we even decided to go in and drill the horizontal section. So the horizontal section was no problem at all to drill or stimulate.

It’s taking a little bit of time to get on flow back currently we had difficulties with our coil tubing unit getting all the plugs drilled out of it. So essentially we stopped at that point. We tested the well. We went back in, tried to remove some of the additional plugs, but at this point I think we’re going to flow the well back for an extended period of time before we go back and do any additional remedial work on it. But overall it’s taken probably 14 months I think. So it seems like an odd amount of time, but with the amount of analysis that we did we felt that was the prudent way to go.

Richard Dearnley - Longport Partners

And I haven't examined the 10-K. Could you put some numbers to what you guess your CapEx in 2013 is going to be? And then talk about how your talent set is wrong for the rest of 2013 as you go forward and what you’re going to recalibrate.

Ian Fay

Sure. Let me tackle the CapEx estimates first. We have basically got about -- now again this has been mitigated recently by some of the carry components of the joint venture as well as the cash that’s come in which we’ll be utilizing. In our current plan we’ve got a total CapEx in the order magnitude of about $50 to $55 million planned for 2013 and that is essentially divided into about -- $15 million of that is approximately what we’ve got currently in terms of land position pro forma to these deals, maintaining our position, filling in some of the net to grosses and otherwise. In addition to that, we’ve got about $8 million that we’ve identified which is fully discretionary which we will be providing a lot of more information in the future to all as we get into the development phase of the Eaglebine with our partner.

Richard Dearnley - Longport Partners

That's $8 million for land?

Ian Fay

That’s correct. I consider that discretionary land CapEx. The $15 million of land that I mentioned before is essentially that which we already have to our 100% holdings, keeping leases extending et cetera. The balance between that and the $55 million total is primarily DSD costs, those that we’ve already incurred in the work that we’ve done with our three wells and then maintenance and some other things along the way for our operating and non-operating wells through the balance of the year.

Todd Brooks

I’d like to supplement that by saying that our CapEx and our drilling pace on our standalone acreage will be a function of the drilling and the information we glean from the JV as that moves forward.

Ian Fay

Right. And the second question is essentially a work in process. We recognize that we have taken our operational requirements down somewhat with the JV as well as the sale of Moulton and we have further, as Todd mentioned earlier, further intention to continue to look for opportunistic transactions, commercial opportunism with our Eagle Ford acres. As a result, the needs for a full operational team as well as some of the more distant lands and others in the group have diminished somewhat and I think that is the primary focus of our reduction. That is also what we intend to take some time to reassess as we get into the development portion of the Eaglebine with the vivid work of our partner, how that translates into what we need as a company in the future. And I think that’s going to evolve as we progress through the 2013 year and I’d like to provide you all with regular updates as we move through those reductions in G&A as well as we get clarity around how we’re going to recalibrate as I mentioned earlier towards the end of the year.

Operator

Your next question is from the line of Robert Kecseg, Las Colinas Capital Management.

Robert Kecseg - Las Colinas Capital Management

I'd like you to touch upon maybe the value or the cost of these three wells with your new partner. And I think maybe that may give some idea to the market about the value of what the deal means to the Company. So could you tell us in little bit about the wells and the cost that they are going to undertake?

Ian Fay

Let me first say that as it relates to the partner and the structure of the JV, as I think we’ve announced just to refresh everyone’s memory, we have a nine well, if you assume all three phases of this project, we have a nine-well carry. So 100% of the costs that would otherwise be borne by ZaZa are being borne by the partner for the first nine wells. The assumption that we and our partner have made related to costs where there is again mindful because these are the first of the series of wells planned, there’s a good bit of data and times that are being applied to these wells, but generally speaking the targeted costs for a vertical completion and that vertical would typically target the lower Cretaceous as Tom and Kevin mentioned, but could target other areas is around $6 million. Yes, it’s completed. Again, that’s fully completed. And for a horizontal well that is in many ways consistent with that which we drilled for the Stingray for the first well, we’re estimating or targeting $12 million of costs for those horizontal completions. Again as you know, this is the business of oil and gas so these are estimates, but that’s the target that we’ve set with our partners to move forward.

Todd Brooks

So all in, nine wells, $90 million. ZaZa is carried on 25% of that.

Robert Kecseg - Las Colinas Capital Management

I just wanted to say is it right in thinking -- you were telling us about some of your neighbors there, the different operators and the success and so forth that they've had, or some the difficulties. Is it fair to say that the Stingray was successful enough to really be able to make this partnership happen? Isn't that really what the gist of what the ability to negotiate the deal came from?

Thomas Bowman

Let me address it because really we have two different plays going on. Remind you back to Todd’s comments about sag pay. We’ve got opposite operators that were drilling shallower than we were drilling into the sand, more the sand silt play. Now that’s different than what we’re after. We’re after that organic rich shale that Kevin mentioned. So we’re drilling a bit -- just above the Buda formation and same target as Range had tested in their well, the same target that we’re testing in this same one that we feel is probably the real winner out here because it’s organic rich. It’s not as difficult to drill it because you’re not chasing very small sand sections if you will. It’s more of an unconventional shale play and what we saw from our initial test, and we saw the same test with Range. Range produced a little bit of oil also out of their well.

We flowed back one set of perfs in our well. We didn’t get the initial gas flow that we expected. We got oil and what’s encouraging is that after stimulation and it wasn’t much very flow back fluid, it was almost immediately liquid hydrocarbon which was the real winner for us. Quite perplexing because we anticipated to have better gas, but later with our geochemical data we were seeing that the maturations and the maturity of the rock was less and we feel the oil was stored in those shales which is encouraging for this kind of area. But we have enough well control across our entire block to validate that with the existing well control.

Todd Brooks

Yes. I’d also like to just comment. My opinion on that, the answer is absolutely yes and I think the importance of this is if you look at the eyes of a strategic partner like we acquired in our JV, the value of data is critical. On the financial side yeah, it’d be great to get a great well and great IP right off the bat, but the data we’ve acquired more technical data on that well than most of the industry had in that area. And then on top of it, even our Cretaceous wells and the wells that are being drilled for the Cretaceous, there hasn’t been a well yet where we haven’t seen similar shows in the lower Eaglebine. So that potential has been there on every well we’ve drilled and we’ve got the data to confirm it both from the Range data that they acquired and our Stingray data. So really a lot of that data is what led us to where we’re at right now with our JV partner. I think they significantly understand the value of that data and it’s very important. So we look forward to sharing a lot of that data in detail with you as we move in some of our investor conferences. They’re able to show illustrations of the well and some of the actual technical data that we’ve acquired.

Robert Kecseg - Las Colinas Capital Management

Thank you very much. That's why I brought it up. I thought maybe it was a little bit underappreciated the points that you just made. Thank you.

Operator

Your next question is from the line of Chris Cook from Zazove.

Chris Cook - Zazove Associates

I was interested -- you said that G&A was going to be down 25% to 35%. I was wondering from what level.

Ian Fay

Obviously from the lofty level that we reported at the end of the year that you see the detail of in the 10-K. primarily it’s going to be coming off of from the standpoint of personnel and we’ve also got across the board we’ve identified multiple areas where we can continue to be more efficient from the standpoint of legal and operational fees. And also keep in mind the G&A level for 2012 was in many ways from an ongoing concern and operational company standpoint, overblown in that the G&A this year will exclude many onetime costs. And what we’re focusing on is the burn rate. Essentially what we want to get to is a lean area on overall G&A that is consistent, that is re occurring that we can manage and that creates an easier pathway to cash flow profitability. So that’s our intent.

Chris Cook - Zazove Associates

Yeah. I guess I was wondering -- so the $98 million, we can expect that to decline by 25% to 35%?

Ian Fay

The $98 million is not an apples to apples comparison. So as we came into the year, we were already functionally well below that and what we’re going to do is off of a reduced base. We’re going to continue to -- as a result of these deals that we announced last week, as a said we’re going to institute this cutting in May. So what you’re going to see -- and starting January 1 we were already off the base in recurring G&A standpoint significantly below that because of the overblown cost associated with many of the things that transacted in 2012. From the lower base in 2013 we will further reduce starting in May and that’s where you’re going to see the 25% to 35% come on.

Chris Cook - Zazove Associates

My original question was what is the base that you’re coming off of 25% to 35%?

Ian Fay

It’s essentially -- if you go across the board, we’ve got a fully loaded monthly expense for ZaZa run rate for 2013 of about $15 million.

Todd Brooks

That’s annual.

Ian Fay

That’s for the full year 2013. And so what you’re going to see is you’re going to see that number come down.

Chris Cook - Zazove Associates

Okay. So $15 million comes down 25% to 35%?

Ian Fay

That is correct.

Chris Cook - Zazove Associates

I'm sorry. Was that a monthly run rate, or -- I apologize?

Ian Fay

No. That was annual. My goodness, no. That would be -- I don’t know if I’d be here right now if it was monthly.

Todd Brooks

You’d be part of that 35%.

Ian Fay

I’d be part of that 35%. So just to put it and to frame it for you, for 2012 we had about $52 million that was in that number that was non-recurring. So again it’s pretty dramatic the drop off that you’ll see for 2013 and what you’ll see is as we move into the first quarter, the first quarter when we get the pro forma deals in, which we announced last week would be I think much more indicative, much more streamlined and a lot more useful to you all and we look forward to getting you there because it will then essentially reset our P&L, reset our balance sheet and give you a view to what we’re going to be in 2013 and beyond.

Chris Cook - Zazove Associates

Okay. So 98 minus 52 is 46, but it sounds like you said as of January 1 you’re at a base run rate of G&A of $15 million?

Ian Fay

That was for mostly salaries. Essentially we’ve got add to that another $10 million that covers some things that will be non-recurring this year like some of the vestiges on tax from the France sale, some other legal director public company expenses that are in there. So that’s kind of where we are. And I’m happy to go into great deal of detail breaking it down for you so why don’t we set up a call separately and I can take you through every line item if you like.

Chris Cook - Zazove Associates

Fair enough. Thanks.

Operator

Your next question is from the line of Mitchell Metzman, Metzman Capital.

Mitchell Metzman - Metzman Capital

I just have a quick question about your wholly-owned block of 19,000 acres, about what your drilling schedule is for the year and timing and allocation of capital for that block.

Todd Brooks

As I stated earlier, our CapEx and our drilling pace on that 19,000 carve out acres, that’s going to be completely a function of the drilling and the information that we glean from within the JV. So we’ll be able to better guide for that probably mid-summer.

Mitchell Metzman - Metzman Capital

So as it stands right now you don't have any plans to drill on that as an operator?

Todd Brooks

We do have plans to drill. When we begin drilling as I mentioned is a function of the drilling in the JV and the pace at which we drill is also a function of what we learn in the JV. So more to come on that front.

Mitchell Metzman - Metzman Capital

Do you guys have any thoughts about the BOE exit rates for this year and next year and the number of rigs that will be running, both operated and non-operated at this point?

Todd Brooks

Yeah. Well, we’ve done quite a bit of type curve analysis work. I’m not prepared to guide towards a 2013 exit rate as it’s still early in the play. Once we have some production history I look forward to providing that guidance at a later date.

Mitchell Metzman - Metzman Capital

And then how many rigs -- or what has your JV partner committed in terms of rigs to fulfill their obligation?

Todd Brooks

Phase 1 encompasses across three wells and our JV partner needs to drill those by the end of the year.

Operator

Your next question is from the line of Peter (inaudible) Fund.

Unidentified Analyst

I'm wondering if you could just review again the $83 million tax expense. I'm not sure if I understood that any of that is recuperable against U.S taxes or it’s all foreign tax that is not -- can't be credited against your U.S -- potential U.S tax situation going forward.

Ian Fay

Essentially that $83 million I can break it down -- and by the way I’d point you to the 10-K as well. There’s a detailed breakdown on the F pages, F31 and F32. But for purposes of the call, generally there’s a statutory tax of $10 million embedded in there, 35%. We’ve got almost a $2 million gain on the warrant. A large part of it is that to your point unremitted earnings that were of the foreign subsidiary that would divest -- there’s a deemed dividend. That’s by the awy $21 million of that is that foreign subsidiary unremitted earnings. You’ve got a deem dividend of $11 million. There’s a valuation allowance adjustment which I mentioned earlier in my comments of $37 million and then there’s a foreign just a rate on the differential that comprises about $6 million. I think with those adjustments gets you that $83 million. The one note I would make is that the adjustment to the valuation allowance of $37 million is something that in the future may be reversed, but likely not completely. A portion of it will be and again this is taken as -- take your income tax expenses down just for further clarity there.

Operator

Your next question is from the line of Pat McLaughlin, UBS.

Pat McLaughlin - UBS

I've got a couple of questions about your CapEx budget and who can call on whom for what. If you've got $23 million essentially pegged for lease acquisitions and netting up and whatever you need to do that are really land-related issues, that leaves you about $25 million or $30 million for actual drilling for 2013. And as EOG begins the three sets of three wells process, assuming they find something that’s worth looking at and going on to the next stage, may they call on you for drilling obligation money on a stage-by-stage basis? Meaning first stage they drill the first of three wells, they like what they see, they’re going to start development right now. Or they wait and they drill all three. Can you be called on for your proration of any drilling obligation? Should they -- do you expect them with success to plunge right ahead and start to develop the first 20,000 acres? Or do you expect it to be three years before you’re called on for drilling to -- you know, drilling monies to be paid to the JV?

Todd Brooks

Hey Pat, that’s a great question and that was an issue that we worked through as we had our dialogue with our JV partner. Our carry is sequential. So the first nine wells for ZaZa are carried. That’s a component of protection that we built in for our own sake.

Pat McLaughlin - UBS

Right. Go ahead.

Ian Fay

Let me address the back end of that question. So first of all as I mentioned, a component of that land expense is fully discretionary to the extent that we needed to we could divert those $8 million to another place or G&P cost as an example. The other thing that we anticipate and we’ve been preparing for and one of the things that has been a mandate of mine and a focus of mine since I took the job last summer was to create a balance sheet environment that was more regular way, meaning to be able to access the capital markets, again very importantly non-dilutive by the way. But we have several different tools at our disposal to do so. One of them is a carve out from a senior secured that allows us to raise a reserve based lending.

As we get into the production cycle and prove up some of these acres, both on our own for the wells we’re getting down now as well as the JV partner gets going on that to our 25%, we will be able to access that line and those relationships more easily. So and there are other aspects of the financing landscape that we’ve been pursuing with different banks to be ready for that outcome. So we have within the context of our model the ability to move money around to accommodate and to be opportunistic and outside of our model the ability to access the capital markets for further development and for further optionality. So I think that’s the general view that we’ve got going forward into the year.

Pat McLaughlin - UBS

Okay, thank you. That is helpful. Let me go back, though. Can EOG call on you for your proration on anything above those three wells in 2013? Is that contractually -- are you obligated if they ring the bell?

Todd Brooks

Okay. So Phase 1 is three carried wells. Once…

Pat McLaughlin - UBS

I understand the carry, I'm just saying they now have drilled three, they have a conclusion. The conclusion is they are no good, we're gone, the conclusion is it is good, we’re going to develop.

Todd Brooks

Once they begin to drill that fourth well, they will be deemed to have elected into Phase 2 and they’ll need to pay us the $20 million and they’re then in Phase 2.

Pat McLaughlin - UBS

So you don't expect -- to paraphrase this one more time -- I'm sorry to keep flogging this, but I'm not clear on whether they can call on any of the $25 million to $30 million of CapEx for the JV's development in 2013 or is that all money that ZaZa intends to work with on whatever you intend to work with it on?

Todd Brooks

The only way we’d be called for money in 2013 from our JV partner is if they began drilling the 10th well and they had already paid us the $50 million.

Pat McLaughlin - UBS

Okay. So that was my original question. They've got to go through all three phases before they can call on you?

Todd Brooks

Correct.

Pat McLaughlin - UBS

Okay. That’s what I needed. On your 19,000 acres, what’s the average lease term left? Or is any of it held by production?

Todd Brooks

The acreage -- both the Stingray and the Commodore are right in that area. So those two wells will hold that acreage by production. It varies. There’s a little bit of acreage that’s expiring later this year, early next year, but most of it is fresh leases.

Pat McLaughlin - UBS

Okay, and the term on those?

Todd Brooks

When we take leases they’re three year terms.

Operator

At this time I’m showing no further questions in queue. I would like to turn the call back over to Mr. Todd Brooks for any additional closing remarks.

Todd Brooks

Thank you all for being on the call today and we look forward to future calls and to updating everyone with the progress our company is making. Thank you and have a good day.

Operator

Ladies and gentlemen, that concludes today’s conference. We thank you for your participation. You may now disconnect. Have a great day.

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