VAALCO Energy, Inc. (EGY) Q2 2015 Earnings Report, Transcript and Summary

Ladies and gentlemen, thank you for standing by and welcome to the Second Quarter 2015 Earnings Report. [Operator Instructions] And as a reminder, this conference is being recorded. I'd now like to turn the conference over to Al Petrie, Investor Relations Coordinator. Please go ahead.

Thanks Lander. And on behalf of the management team, I welcome all of you that have joined today's conference call to review VAALCO's second quarter 2015 operating and financial performance. After I cover the forward-looking statements narrative, Steve Guidry VAALCO's Chairman and CEO will provide a brief high level financial summary, and will then review our operations in West Africa. Following Steve's comment, Greg Hullinger the Company's CFO will provide a more in-depth financial review and update to our 2015 guidance. Following the presentations, VAALCO's management team will be pleased to answer any questions you may have. With that, let me proceed with our forward-looking statements guidance. During the course of this conference call, the company will be making forward-looking statements. We caution you that any statement that is not a statement of historical fact is a forward-looking statement. Forward-looking statements are those concerning VAALCO's plans, expectations, future drilling and completion activities, expected capital expenditures, prospect evaluations, negotiations with governments and third parties, reserve growth and other operations. Statements made during this conference call that address activity, events or developments that VAALCO expects, believe or anticipate, will or may occur in the future are forward-looking statements. These statements are based on assumptions made by VAALCO based on its experience, perception of historical trends, current conditions, expected future developments and other factors it believes are appropriate in the circumstances. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond VAALCO's control. Investors are cautioned that forward-looking statements are not guarantees of future performance and those actual results or developments may differ materially from those projected in the forward-looking statements. VAALCO disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Accordingly, you should not place undue reliance on forward-looking statements. These and other risks are described in yesterday's press release titled Forward Looking Statements and in the reports we filed with the Securities and Exchange Commission, notably the 2014 Form 10-K filed with the Commission on March 16,2015 and Form 10-Q filed with the commission on May 7, and August 06, 2015. Please note that this conference call is being recorded. Having provided you with our forward-looking statement guidance, I will turn the call over to Steve Guidry. Steve?

Thank you Al, good morning, everyone. And welcome to our second quarter 2015 earnings conference call. I want to begin by saying that as you saw on our earnings release yesterday and we'll hear on our call today, we’re continuing to improve the depth and breadth of information that we’re providing. We began that process in early 2015 and we’ll continue to expand our future disclosures and discussions with the whole statistical need to a better understanding of our current performance and provide investors with improved visibility into our future performance. As mentioned in our earnings release, we posted an investor handout on our website this morning in the Investor Relation section under the webcast presentations path entitled second quarter 2015 supplemental information. We'll be referencing and reviewing information that is shown in that presentation. Those new disclosures include non-GAAP measurements that are comparable to what we see presented by most other small cap E&P companies. These measures are intended to provide more information on our ability to generate cash rather than just GAAP net income, which is key in this low price environment. I’ll provide a summary of our quarterly results and operational highlights. Greg will then follow with the review of the financial information in more detail. But first let me take the moment to introduce our new Chief Operating Officer, Cary Bounds. Cary has been a quick study he joins us from Noble Energy where he held the position of Business Unit Manager with responsibility for Noble’s operated properties in Equatorial Guinea. The EG business unit for Noble was a sizable West Africa operation with growth production in excess of 65,000 barrels of oil equivalent per day. We’re very excited to have Cary as part of the VAALCO's leadership team. Turning to the summary of our quarterly results, we benefited from higher production slightly higher oil prices lower production cost, and lower G&A cost on an absolute and on a BOE basis compared to the first quarter. All of which contributed to the increase in our adjusted EBITDAX. If you turn to Slide 6 of the supplemental information presentation, you will see that our adjusted EBITDAX per BOE improved significantly compared to the first quarter of 2015 with price realizations were lower and cost higher and also was up compared to the fourth quarter of 2014 when we had realizations that were $4 per BOE higher than in the second quarter. We’re getting good benefit from the increase in volumes from our development program even though we’re in a low price environment. I do want to mention that the improvement in G&A per barrel from $8.47 in Q1 to the $4.63 per BOE in Q2 includes an adjustment of around $1 per BOE. We expect G&A per barrel to be closer to the $6 per BOE level in the future. If you turn to Slide 7, you’ll see a more detailed breakout of our production expenses for the two quarters. The cost on a BOE basis went down about 16% within just the first quarter for the central processing facility engineering charge. These charge help to categorize costs and allow us to show what some of our fixed costs are versus variable. The FPSO and the domestic market obligations, our long-term fixed commitment and the cost just don’t vary much from quarter-to-quarter, but they account for about 40% to 45% of our lease operating expense. The other cost include aircraft, boats, field personnel and other operating expense have both a fixed and variable component. We estimate that the fixed cost component of our production ex business is approximately 85% with the remaining 15% being variable. As a result of this low variable cost component, every incremental barrel we bring online will only marginally increase cost and thus add to our profitability. Turning to Slide 8, we’re focused on increasing cash margins by reducing cost wherever possible. Ongoing initiative to produce production expense and G&A expenses have already yielded significant and sustained cost savings of 10% to 15% some of which were forecasted in our guidance. The full year benefits will be more evident in 2016. These initiatives are sitting on finding ways to become efficient at operating our assets. For example, we become more efficient and how we manage logistics resulting in fewer services vessels and aircraft supporting our operations. We’ve also worked with a number of our suppliers to reduce day rates and unit cost to a level that reflects the current market. We’re also in the process of staffing an administrative cost review. On both on absolute and on a BOE basis, there were significant improvement from the first to the second quarter. To continue our focus on long-term G&A reductions we’re committed to taking additional actions in this protracted lower for longer price environment. With the largest development project ever undertaken by the company the Etame 10-H extension projects winding down we will look to streamline the organization and rationalize the workforce. As we bring on additional wells increasing production volumes and continuing to achieve the 15% to 20% - 10% to 15% cost savings, our cash operating cost per barrel should decrease allowing us to realize higher margins per BOE. For the second production net production averaged 4,546 barrels of oil equivalent per day compared to 4,260 barrels of oil equivalent per day for the first quarter. That was the upper end of our guidance for the quarter which was 4300 to 4600 per day despite delay in getting the Southeast Etame well online. Production increased in the second quarter due to a full quarter of production from the Etame 10-H and two months of production from the Etame 12-H well. Both of these wells were discussed in details during last quarter's earnings call. We believe production will continue to grow in the third quarter with the benefit of the Southeast Etame 2-H well that came online in July and the North Tchibala 1-H contribution. The work over program includes two wells currently offline on the Avouma South Tchibala platform with an additional one to two work over is possible beyond that. We recently decided with our partners to move the rig from the SEENT platform after it completes the current drilling of the North Tchibala 1-H well to the Avouma South Tchibala platform for the work over program as these two initial wells can have immediate impact on production. That will give us additional time to monitor the production and performance that we hope to achieve from North Tchibala well before we drill the second well for the field. Taking this all into account we expect our third quarter production to be in the range 4,400 to 4,700 barrels of oil equivalent per day. For the full year we’re now in the range of our guidance and increasing the lower end. We now anticipate our 2015 production to average 4,100 to 4,600 barrels of oil equivalent per day. We still expect upside to our production this year and we’ll revisit our annual estimate next quarter as we have additional results from the third quarter drilling and work over program. Also this quarter we negotiated a new crude oil purchase and sale agreement with Glencore. The term contract is similar to the sale agreements we had in place prior to May of 2014. In this new contract Glencore will market the Etame crude for a period of one year at an index price related to dated rent. This allows us to avoid spot market sales removing much of the market risk. The new contract with Glencore also provides the sellers with control of the looking schedule, which we believe will give us added opportunity to maximize price, while limiting the potential for higher lifting cost. We’re very pleased to recently announce that the borrowing dates under our IFC credit facility was reaffirmed at a full $65 million, which is the maximum capacity provided under that facility. The loan is on a mid-year and end of year borrowing based redetermination schedule. The covenants under the agreement remains unchanged including the removal of the debt to equity ratio covenants announced in May of 2015. This gives us $50 million of headroom above our current loan balance of $15 million including our cash on hand at June 30 of $78 million along with the $50 million an undrawn capacity. We ended the quarter with $128 million of total liquidity. However, liquidity adjustment for receivables of crude liabilities and payables at the end of the second quarter was $95 million. Moving now to an operational review we had a number of very positive recent developments. We successfully drilled and completed the Southeast the Etame 2-H well and are progressing with the drilling of the North Tchibala 1-H well. Both of these wells are located on the recently commission SEENT platform which I’m proud to report came online trouble free the first oil from the Southeast the Etame 2-H well. The Southeast the Etame 2-H which was drilled to develop an exploration discovery made by VAALCO in 2010 came on production on July 17 at about 3,400 barrels of oil per day growth was no H2S. This rate with the electric submersible pump on it’s lowest possible setting combining this with very strong reservoir pressure gives us confidence that this well would exceed our predrill expectation. As previously disclosed Southeast Etame 2-H experienced mechanical problems during the drilling phase, which resulted in having to redrill approximately 70% of the well board. With the addition of Southeast Etame Wells to our portfolio, the Etame rig achieved a peak production rate of greater than 21,000 barrels a day in July, which was the highest rate we’ve seen since March 2012. The rig has now moved to the North Tchibala 1-H well, where we have side tracked the well after recent delays due to stuck pipe. Fortunately, we were a week ahead of the drilling curve when the incident occurred. We still anticipate first oil by mid to late September despite the mechanical issue. Prior to VAALCO having an interest, the North Tchibala field was discovered in 1977 where one exploratory well and total of three subsequent appraisal wells identified multiple reservoirs with several zones testing to flow hydrocarbon at significant rates. While we’re targeting Dentale formation that has never been produced before on the block, VAALCO efforts in the North Tchibala field represent development drilling, not exploration. Hydrocarbons are known to exist in as many as seven different reservoirs representing as much as 100 million gross barrels of oil in place. As we look ahead past the work over program that we alluded to earlier, we'll consider further drilling on a well-by-well basis -- as previously reported VAALCO and its partners contracted with Transocean for the use of the Constellation II jackup rig. The contract runs until July 5, 2016. We have a portfolio of viable development well and work over opportunities as options for continuing the program beyond the initial well campaign. Additionally, we've hired a rig broker to actively market the rig to other operators for any remaining unutilized contract term. Should VAALCO and its partners elect not to fully utilize the rig for the entire contract duration and if the sub lease options are not available, a contract termination charge would be incurred. Turning our attention to the centralized crude sweetening facility. Our engineering efforts continue to find the most cost effective alternative, crude sweetening option for the removal of H2F from the affected wells, Ebouri and Etame. We mentioned in our last call, the option is under consideration to accomplish the goal of low cost crude sweetening. Since then, we've established an integrated project team with our partners to ensure alignment and the efficient use of all available resources to find the best solution. Our teams currently are performing sensitivity analysis related to variations in production profiles, various souring scenarios, and maximum H2S concentrations that may need to be treated. We've held multiple technical workshops with our partners on crude sweetening design, ensured an economic solution be identified, the project concept, timing, and start up date could be known as early as the fourth quarter of 2015, with a goal of reestablishing production from the areas impacted by H2S as soon as practical. Turning our attention to Angola, we've made progress in evaluating recently reprocessed seismic data on Block 5. We’re very pleased with the uplift and our ability to image the subsurface with this new data, an example of this can be seen in our Company’s update presentation on the Company’s website. We've developed a number of very attractive pre-salt leads and prospects. Based on our initial assessment of volume, the top four prospects and leads have been estimated total gross unrisk mean recoverable resources in excess of 800 million barrels of oil. While we believe the pre-salt targets on Block 5, represent a game changing opportunity for VAALCO. We decided last fall that in the low price environment, we need to better manage our risk profile. To this end, we’ve opened the data room and have met with a number of major oil companies and large international E&P companies who have expressed interest in joining us and Sonangol P&P on the Block. VAALCO will be looking for a carry arrangement on the remaining commitment wells in Block 5, as part of the form up. In addition, we’re pleased with the significant process on Sonangol P&P’s outstanding unpaid balance with cost incurred on the Block since their assignment in 2014. We continue to have constructed dialogue with Sonangol where they have confirmed their intent to be a full paying partner in the Block including the back cost as a result of the previously defaulted party. I also want to remind our investors of what are commitment entails in Angola. You may be aware that our remaining three commitment wells in Angola, each have a termination cost of $5 million net to VAALCO. We do not plan to drill any additional exploratory wells there until late 2016 at the earliest. I would reemphasize that drilling additional wells on Block 5 will depend on our cash position, the forecast of oil price at the time of the rig commitment, the revised estimated cost to drill the wells since service cost have fallen, the success of our efforts as well as the size and quality of the targeted prospects. Now, looking at Equatorial Guinea. A very positive development has occurred regarding GEPetrol, the national oil company of EG, who is the current operator of the Block. GEPetrol has undergone a leadership change that we believe marks a significant shift in the philosophy and direction of the Group. We believe the new leadership is much more closely aligned with the ministry of mines industry and energy, which could lead to a more reasonable position as it relates to operatorship on the Block. The minister has asked that we meet with the new GEPetrol leadership to move this Block forward in that regard Kerri, will be travelling to meet with GEPetrol and then ministry again in the coming weeks to further our efforts. At Mutamba, the Mutamba Iroru block on shore Gabon has seemed to measure progress this quarter with VAALCO recosting the capital required to develop the Block. We’ve identified alternative, lower cost development options, which could lead to a more economic project. We’ve met several times recently with our concession partner and the government in an effort to move the project forward and finalize the revised PSC. Let me now turn the call over to Greg, for more details on the second quarter and guidance for the balance of 2015.

Thank you, Steve. As Steve mentioned, I'm going to provide a review of the key financial information pertaining to the second quarter of 2015, that we reported yesterday in our earning press release and the SEC form 10-Q. I will also be providing additional guidance information pertaining to the third quarter and full year 2015. First, I would like to mention that you probably saw that we issued our press release yesterday afternoon and then followed it up quickly with the table revision. We experienced a software glitch that is still bit of a mystery but we will be working with the software provider to understand and prevent the reoccurrence in the future. I might mention that this is part of our cost savings initiative. This is the first quarter that we have used this software and so it maybe a little bit of learning curve. In any case, the 10-Q filing was not impacted and with that I am now ready to move to financials. The Company reported adjusted net income of $0.6 million or $0.01 per diluted share for the second quarter of 2015. Adjusted EBITDA was $16.3 million in the second quarter of 2015. The second quarter adjusted numbers are before $5.8 million non-cash impairment charge related to the Etame Marin Block, offshore Gabon. Lower projected oil prices and additional development cost at June 30, 2015 they were using the impairment valuation, one of the factors that brought about this impairment charge. Including the impairment charge, the net loss for the second quarter was $5.2 million or loss of $0.09 per share. This compares to a net income of $24.7 million or $0.43 per diluted share in the second quarter 2014. The impact of lower oil prices is clearly seen in our revenue number. Revenues of $27.1 million reported for the second quarter 2015, were substantially lower than the $52.1 million of revenues reported for the same quarter in 2014. The average price we received in the second quarter of 2015, was $59.16 per barrel compared to $108.24 per barrel in the second quarter of 2014, a decrease of 45%. If there is any good news with the $59.16, it would be that was higher than what we received in the first quarter of the year. Barrels lifted in Gabon during the second quarter of 2015 of approximately 455,000 barrels more comparable for the approximately 477,000 barrels lifted in the same quarter in 2014. Revenue is a function of both price and the amount of barrel sold via the crude lifting's that occur in Gabon on approximately monthly basis. Since we can only sell what we produce, production is the key matrix that is within our control. Production on a networking interest after royalty basis was approximately 404,000 barrels or 440,000 of oil per day. This production is approximately 6% higher when compared to approximately 380,000 barrels or 4,200 barrels of oil per day on the same basis last quarter. The increase in production is expected to continue to grow during the remainder of the year as a result of our current development well, drilling and work over program that Steve described a few minutes ago. That was working interest in the inventory or the FPSO vessel excluding royalty barrels at June 30, 2015 was approximately 27,000 barrels versus approximately 16,000 barrels at June 30, of 2014. With that, let me move to other key financial components for the second quarter of 2015. Operating loss was $1.0 million in the second quarter of 2015 compared to an operating income of $33.8 million for the second quarter of 2014. The operating loss, obviously heavily impacted by the reduction of price of oil. Production expenses for the 2015 second quarter were $8.9 million compared to $4.8 million for the 2014 second quarter. The second quarter 2014 benefited from non-operational adjustments recorded during the period including an accrual true-up, while the first quarter of 2015 included $3.60 per BOE charge related to expense in costs for the design of a centralized H2S processing facility. Guidance for the third quarter 2015 for production expenses is $8 million to $9 million excluding work over costs. We continue to believe production expenses for the full-year will be in a range of $30 million to $33 million, excluding work over and the nonrecurring items associated with the H2S central processing facility charge that we recorded in the first quarter. As we mentioned last quarter, we have budgeted for two third quarter work over in the Avouma and South Tchibala field to light electrical submersible pumps at an approximate combined net profit about $5 million to $6 million. For the full-year, guidance for work over cost is being put in a range of $5 million to $12 million as an additional one to two or band of maintenance work overs are possible in the fourth quarter. Exploration expense for the second quarter of 2015 was $1.1 million compared to $3.3 million recorded in the second quarter of 2014. Exploration expense during the second quarter of this year includes a $0.6 million non-cash charge for write down of the undeveloped resource leaseholds on a property we have in Montana. The remaining value of the leasehold for this property on a balance sheet is $0.6 million, so essentially well half of that investment off during the quarter. As there are no additional exploration wells budgeted for in 2015. Exploration expense for the remaining two quarters in 2015 is expected to be minimal. DD&A for the second quarter of 2015 was $9.3 million compared to $7.0 million in the same quarter of 2014. The increase reflects a higher composite DD&A rate for the offshore Gabon assets, due to inclusion of platform and development well expenditures. Second quarter DD&A was $20 per barrel. Our guidance for the third quarter has been raised accordingly for new investments for range of $20 to $22 per barrel and we expect the full year to be between $17 and $20 per barrel. G&A expense for the second quarter of 2015 totaled $2.8 million which was down 10% compared to $3.1 million recorded in the same period in 2014. Guidance previously projected a net G&A expense to be in the range of $12.5 million to $15 million in 2015. Of these amounts cash G&A is expected to be in the range of $9 million to $12 million with the remainder $3 million to $4 million in non-cash G&A. Overall, we expect to end the year at the upper end of the guidance previously provided. Income tax expenses for the second quarter of 2015 were $4.3 million compared to $9.0 million in the same period in 2014. The decrease in income taxes reflects the impact of the lower sales prices received for oil sales during Q2 2015. Cash and cash equivalents including restricted cash totaled $78.1 million at the end of the second quarter of 2015. This compares to $91.5 million at the end of 2014. Capital expenditures spent totaled $13.1 million in the second quarter of 2015. I will now hand the call back over to Steve.

Thanks, Greg. I'd like to close out with just a few additional comments before we go to Q&A. On Tuesday morning, we announced that our Board had approved the repurchase program of 5.8 million shares of common stock, which represents approximately 10% of our outstanding shares. The authorization provides for the purchase of shares in the open market transactions from time to time during the next 18 months, subject to normal SEC guidelines. This action by the Board in response to the significant decline in our stock price underscores our confidence in the strength of our balance sheet, the quality of our assets, and our ongoing ability to generate cash flow. We believe our common stock at the current price represents a compelling investment opportunity, and this is an excellent use of our cash on hand without causing us any liquidity concerns in the future. To position the Company to take advantage of potential opportunities, we see a rising in the current downturn that could facilitate our desire to grow the Company. Earlier this summer, the Board established a growth focused looking group made up of select Members of the Board, together with members of the Management team, responsible for executing on building the Company's future. This group is considering a multitude of value adding opportunities and funding alternatives as part of their remix. Lastly before closing, I'd like to welcome our newest member of our Board of Directors, Steven Pully. As we discussed in the news release on Monday, Steve has over 25 years of experience in capital markets, finance, investing and legal matters. He also has extensive Board participation and leadership experience, having served in a variety of roles on a number of Boards, and as many years of industry involvement. We are confident that Steve will bring a broadened perspective and a new dimension to our Board of Directors. Al, I think we're ready to take questions.

Okay Lander, we're ready to take questions. I ask the participants, please limit their questions to one and a follow up. Lander?

And we will go directly to the line of Leo Marina with RBC Capital. Please go ahead.

Hey, guys. I was hoping you could reconcile some of this production guidance. I think if I've heard you right, you guys were saying 4,400 to 4,700 barrels a day in the third quarter, but you also quoted this July production rate of 21,000 barrels a day, which -- my math is right is around 5,200 barrels a day. So it sounds like very strong July, but can you help me get to the third quarter guidance there. Are you expecting wells go offline in the next couple of months here, August, September, how should we think about it?

Leo, good morning by the way. I think the 21,000 barrel a day peak rate was in the first few days that Southeast Etame two rigs well came online and having - turning on a reservoir that's never been produced before, you generally get some amount of higher decline in the first days, weeks of the wells performance. It's still doing very well. Still far exceeds our expectations, but that was definitely a peak grade that we had achieved for just a short period in July. So, that's part of the answer. Going forward, we have in the third quarter, we looked to bring in that North Tchibala well, right now it's scheduled for very late in the third quarter, so we don't get any more additional benefit until that well is completed and so that's really what we're taking into account and we're trying to be conservative. This is the first time that we really provided guidance, and the other thing that's impacting it as well, we do have a six days shutdown in the third quarter which is pretty - going to have an impact on our production in Q3 as well.

Okay. That's helpful in terms of the production. Just trying to get a better stance of your capital spend in both the third quarter and the fourth quarter here. Just trying to figure out what's left, the spend or the budget for the rest of the year here?

Our guidance makes the assumption that we're essentially going to potentially continue to grow throughout the end of the year. If you look at the current drilling program, if we were to discontinue drilling with the Constellation II at the end of the work over program, then definitely we'd be on the lower end of the CapEx guidance. If we continue to drill through the end of the year, then we're going to find ourselves much closer to the higher end of that production guidance that's kind of how we went about establishing the book in. The third quarter CapEx is going to be down because we're going to be using the rig to do expense work overs. So, to the rigs being working on capital program all year, it will move up of that program to do the two work overs Etame, and that will reduce our third quarter CapEx. But at the most likely scenario is, goes back to drilling and we finish off the year drilling additional development wells and so our fourth quarter CapEx looked a lot like our second quarter CapEx.

Okay. That's helpful, and I guess do you guys have any anticipation that you’ll have lower lifting’s in the third quarter? You had very strong sort of over lifting’s in the second quarter. Is that going to reverse itself out in 3Q?

We expect that, just as in the second quarter, we’ll have strong lifting’s in the third quarter. We did have a minimal lifting in July, but that will all picks itself between now and the end of the third quarter.

Frankly, after we finished lifting the volumes in July, we had 206,000 gross barrels in more of the FPSO and as of this morning there is over 450,000 barrels in the vessel.

Okay, that’s helpful for sure. Thanks guys.

Thank you. Our next question comes from the line of Sameer Uplenchwar with GMP. Please go ahead.

Hi, thank you guys and congratulation on a good quarter. I’m trying to understand how should I think about 2016? I know it’s a bit early and commodity prices keep on changing, changing on a spot like this year it seems, because you have the development wells and the exploration wells, is there some plans regarding like Angola next year. And from a CapEx spend perspective, how should I think about it that’s actually constrained you’re starting on the buyback program? Could you give some color on that end?

We will try to provide a little color you’re right. It’s awfully early for us to be providing 2016 CapEx but and to your point with the uncertainty around oil price makes it even now much more difficult but let me say this about that. We are working with our partners right now at Etame to land on a final view of what our 2016 capital might look like, but with commodity prices being so volatile, our Etame drilling in 2016, honestly, could be anywhere between zero wells drilled in an extreme low price environment to as many as 4 wells. So, there is quite a bit of variability there and we are going to make those decisions well by well, one well at a time based on all the factors that we have before as oil price, the quality of the opportunity etcetera. We also have uncertainty around the crude sweetening project. We are working to finalize the plan there but end of this year, beginning of next year we will be landing on sort of with the viability and the timing of that might be, that could impact our 2016 CapEx and then the last thing of course is the timing of studying the presale well at Angola. So a lot of I will try to give you better formal answer but a lot of uncertainty still remains there in that regards.

Got it. Could you go into, like what was the thinking behind the buyback program and how should we think about that? Is that dependent on what the spending is going to look like in 2016 versus 2015 like is that going to be the driver of that program if you’re not going to spend you’re going to buy back, vice versa?

We certainly did quite a bit of internal analysis around the opportunity and saw that our stock looked to be a great investment opportunity for the company. We did look at and evaluate the ability of the company to execute the share buyback to the point you just made and we felt like the way we have authorized that, the purchase up to 10% of the outstanding shares over the next 18 months gives us a bit of run rate. And for us to do that if that’s necessary and the bottom line is we felt we had adequate liquidity to execute on the program. So I think it’s fair to say that if oil prices were to improve and our CapEx was going to be minimal, you’ll probably see more. If the opposite happens you’ll see less.

Got it. If I can squeeze in one more sorry. Trying to understand how, like the options with the each list of leadership like you said that we’ve spoken earlier in July, you had explained about getting a jack-up rig. And could you explain how that whole process works? Just to get an idea like what type of capital spending are we thinking about ghostly?

Yeah. So, as we come to the end of our sanction project which was the Etame and SEENT development, we had several options in terms of how we might utilize that. One option was your question about the centralized sweetening of the facility or was it about the rig?

Both. I mean, just trying to understand like how should we think about it? Like Chris was trying to put some capital numbers around it, like is it going to be 30 million, 50 million, 70 million? Just so to understand how you’re thinking about the whole process. I know it depends on the price of oil but internally what all options do you have on the table and how you’re thinking about it including for the H2S sweetening?

Yeah, okay. So I’m sorry. I misunderstood the question. I thought you’re asking about the jack-up rig. On the centralized sweetening facility, we will land on options like I said, into this year, beginning of next year. One of the things that to give you an idea or the kind of things we’re looking at. There is an option to do some chemical treating but that’s going to be low volume. It’s not going to provide much flexibility on how much sour crude we can treat. There is option for us to install modules on existing platforms and treat a portion of the sour crude. There is the option for us to install a larger facility and place it on a mobile like a mobile production unit. Most likely a decommission drilling rig and pull it alongside the platform and use it as the basis for the sweetening facility. Those are sort of the some of the engineering solutions to the problem. As far as spending in 2016, the majority of the spending would be two components really. Engineering and long lead item, if there were any and we just haven’t yet done enough engineering to determine exactly what that number would be. But we do believe that whether we pursue chemical solution, whether we pursue a module solution, or whether we pursue a mobile unit, the cost of the facility is going to be significantly less that what we had initially estimated when we were planning to build a brand new sort of facility with its own platform. So there will be cost savings to be enjoyed but we are not at a point yet where we can talk about exactly how much.

All right. Thank you so much.

Thank you. Our next question is from Bill Dezellem with Tieton Capital. Please go ahead.

Thank you. Couple of questions. The first one is relative to Angola and the block 5 seismic. Is the processing complete? Or would you be doing more processing in addition to the evaluation you’re under now?

The processing work is complete though. Good morning by the way. The processing work is complete and I mentioned in the prepared comments if you go on our website and look at our investor presentation, you’ll see the kind of uplift that we have enjoyed as a result of this more modern processing of the 3D. The imaging is just remarkably better than we had prior. So the processing is complete. What we are continuing to do is really the analysis and evaluations of that processing. And so when the geo scientists and the geo physicists look at the new improved imaging, they use that information to identify structures or statographic trace and then with that they estimate volumes and then we can start to prioritize our opportunities on that basis. So that part of the work continues. But the actual processing itself of the data is over.

That is helpful and you’ve mentioned that the image quality is substantially better than what you had before. Is there is the new image make it clear why you did not have a successful well earlier this year and to the point that had you had this data, you would have not drilled that well?

No. I mean it doesn’t couple of things about that. Seismic data allows you to see structure and on the Kindele well, we actually found exactly what we were anticipating in terms of structure, in terms of sand volume. It was all there. What has happened is the oil that moves to the system had apparently bleached through seal the salt and had moved on and there was just water in the system. So, seismic data is not going to do much to help you see that in these circumstances, but our focus is both post-salt and pre-salt but it’s primarily pre-salt. I’ll make that distinction because Kindele was a post-salt well whereas the significant upside potential on block 5 is pre-salt. And most of our processing work that we have done, or evaluation work I should say that we’ve done is focused on identifying pre-salt opportunities. That’s where the big volumes are.

Great. That is very helpful and lastly an accounting question. How does the low price, oil price that is, affects the cost account and your taxes?

Interesting question. Well in terms of the cost account, let me just go there, the cost account is with fees all of the cost that we spend on the block. So, our operating expenses and our CapEx, we put that into the cost account for recovery. If the oil proceeds due to low oil prices don’t allow us to recover our cost in anyone particular listing then they continue and they say on the sheet we will get the credit for that at a later point. All that we received for cost all recovery is of course free of income tax in Gabon so is that 70% criteria that once you produce the oil and you taken out the 14% royalty like it was 87% of that 87% 70% of the oil is available for recovery under cost account. The remaining 30% of that actually does draw tax so there’s always that minimum 30% that draws, but right now we’re in a full cost account recovery mode, because of the cost that we’ve incurred and with the development that continues. So our income taxes have been low as it will continue to be low as we continue to cost account either fall or largely fall. So that’s a bit with how that works I mean low cost or low price environment just generates less revenues and there’s less revenue in order to cover those cost that we put into that account. If the prices were higher you will get your cost recovery quicker, but the good news is of course it won’t go over into the future period.

So just to be clear what you that last part which is the low price means that you the cost account last longer meaning that you’ll have low tax rate or a lower tax rate for your longer period of time than you otherwise would have with higher prices?

Exactly right, Bill.

Thank you both and I appreciate the time.

Thanks Bill.

We’ll go to line Joe Pratt with Stifel. Please go ahead.

Hi Greg and Steve. Just roughly what was your barrels of oil production per day net to VAALCO. December 31, March 31, and June. I’m just trying to get us and also baffled by this bullet point here that said you had 5,900 barrels net to your account at peak oil time here I guess in July and why it would drop off to 4100 by the end of the year?

Joe we actually don’t have the numbers of those periods right before, but glad to take this offline in kind of reconciled numbers with you. The function of certainly when you call a 21,000 barrels a day one doesn’t take out the royalties barrels from that and take it down for interest so I’m not sure that part of the difference. But Steve mentioned our production guidance is the bit under conservative side we do expect to continue to grow production through the year and type of the work over as well. But to help you with numbers on those periods. I said after the call I’ll give you a call and we can just talk through them.

Okay so what it in the just in the June quarter it averaged what was the average to your net account?

For second quarter as you…

Yeah the June quarter.

It was 45 one-off maybe.

Okay. So if you have the firs said wells adding at least 500 barrels that would take you up to 5,000. And then if this next well which is the first time you’re going into the Dentale if that has 500 could that take you up to 5,500 or you have a decline curve on the prior production?

You certainly have the decline curve on the prior production and as I mentioned a little earlier we had the early time decline on things like Southeast Etame well. So it’s kind of an added impact that’s part of it. And we had the downtime in the third quarter I mentioned a little earlier too as well that impacts that third quarter production.

We’re planning to shutdown our FPSO and if you bring wells on ordinary periods where you take the other wells on the platform down, while you do the interconnect or can bring them up so…

Okay.

Those are operational situations that impact that.

Okay so you expect will you drill this year the second Dentale well which would be the third well in the same platform?

That's the current plan, it’s still in the lineup. We have no reason at all to believe that that second Dentale well is not going to deliver what we have always thought it would deliver. The partners have asked us to not drill it immediately back to back with the first Dentale well. So that was convenient, because we had wells down on the Avouma that we could move to and so we’re going to move there and we’ll continue to work with our partners to see when all of us are ready to move back to drill the second Dentale well. So it’s kind of a opportunity on the shelf and we’re waiting for the right opportunity to move back to SEENT to drill it. We have a high level of confidence that that well will perform.

Okay. And the Avouma - how many wells are there in that Avouma area that are now being drilled?

Avouma actually the current plan is to not drill any it’s work horizontally we have two work over plan of the third quarter that might be extended. We have the option to extend it to as many as four.

That could bring on how much production?

Yes, it's going to be - well one thing I’ll say first of its very low risk because they work over so virtually no self surface risk returning the wells back on and they’re going to produce. But we think the total additional production is somewhere in the 2000 to 2300 barrel a day range impart owing to the fact the Avouma has some capacity constraints it’s not well capacity issue it’s a facility.

Okay. Well if the Avouma comes on and then the second SEENT well successful, are you bumping up against an FPSO capacity?

At some point in this development program we may find that we’re bumping up against that capacity and can't say for sure when that is but it’s a good problem to have and what you may see is if that happens which you’ll see is that you’ll see some peak shaping where it will be limited to a certain capacity over period of time. But with natural decline will soon have all the wells back in capacity.

Okay. And what is the peak if you’re talking here on bullet number 5 or 6 you got 21000 DOPD is that peak capacity on the FPSO?

No, the FPSO capacity is 25,000 barrels of oil per day.

Okay.

And border capacity is another 7,000 total fluid capacity about 32,000.

All right, Greg thanks very much for answering my questions.

Thank you, Joe.

Next we’ll go to line of Neil Nelson with DERS Group. Please go ahead.

Can you give me any guidance on the production on Mutamba in 2016 and will the first well and the second well in Angola be both a post and presale production type of effort or are you looking only at presale?

Thank you for that question Neil. Mutamba we really don’t have currently a scenario that where we would see production from Mutamba in 2016. As we said in the call we were still working with our partner and with the concessionaire to resolve some difference around the PSE that’s been proposed by the government and trying to get that behind us. In no event do I see us being able to accelerate in Mutamba to the point where we have production in 2016. As it relates to your second question, which was the Angola well, it’s early we have - like I said we have, we’re still evaluating, which prospects are going to be our priority. We’re focused on the presale. What we would do is we’ll look at the best presale opportunity and then if it has pull so potential in addition to that, that only move that well up to priority well. But I don’t want - I just what I can’t say for sure that our next well will be built on pro sale and pre sale until we finish the evaluation.

So from a risk management standpoint you have yet to make that decision is that basically what I understand?

Yes, that’s a first statement. We have not yet selected our top prospect for Angola block 5 that work is still underway.

Thank you.

And there are no further questions.

Okay. Well, I want to thank everyone for your time this morning. And hopefully the added information that we provided, the more granularity on our business you’ll find helpful. It’s our intention to continue to - up again in this regard and continue to provide the additional specific data that hopefully you find useful. Thank you very much.

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