VAALCO Energy, Inc. (EGY) Q4 2014 Earnings Report, Transcript and Summary

Ladies and gentlemen, thank you for standing by and welcome to the VAALCO Energy end of year 2014 earnings report. For the conference, all the participants are in a listen-only mode. There will be an opportunity for your questions. Instructions will be given at that time. [Operator Instructions]. As a reminder, today's conference call is being recorded. I will turn the conference now to Mr. Steven Guidry, Chairman of the Board and Chief Executive Officer. Please go ahead.

Thank you, John and good morning everyone. Welcome to VAALCO Energy's fourth quarter 2014 and full year 2014 earnings call. With me today are Russell Scheirman, our President and Chief Operating Officer and Greg Hullinger, our Chief Financial Officer. We have a lot to cover this morning. So to get us started, I am going to ask Greg to review our cautionary statement first.

Thanks, Steve and than s for joining us on our call today. After I cover the forward-looking statements narrative, Steve Guidry, VAALCO Energy's Chairman of the Board and Chief Executive Officer will provide a high level summary of the financials, comments pertaining to the current low oil price environment and updates on our operations in West Africa. Following Steve's comments, I will provide a more in-depth financial review and 2015 guidance and then Russell Scheirman, the company's President and Chief Operating Officer will provide a review of our operations in Gabon, Angola and Equatorial Guinea. Following all three presentations, we will be pleased to answer any questions that 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, beliefs or anticipates, 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 that 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, 2014. Please note that this conference call is being recorded. With forward-looking statement guidance taken care of, let me turn the meeting back over to Steve.'

Thank you, Greg. I am going to spend some time talking about our quarter financial, as Greg pointed out and a little bit about our operational results at a very high level. And I want to begin first by apologizing for the delay in the timing of our scheduled conference call. We needed a bit of extra time to complete our final review of our impairment evaluation with our auditors. So let me begin with a little bit of our results. In terms of our fourth quarter 2014 VAALCO reported an adjusted net income of $9,000 or $0.0 per diluted share before the impact of the $98.3 million non-cash impairment charge that we recorded to write down a portion of our asset because of the decline in oil prices. Including this charge, our fourth quarter reported net loss was $98.3 million or a loss of $1.70 per share. This compares to net income of $26.4 million of $0.46 per diluted share for the comparable period in 2013. Greg will give more information related to the impairment charge later. The decrease in the adjusted net income was primarily attributable to the lower revenue resulting from substantially lower oil prices and a reduction in lifted volume in 2014 versus 2013. We ended the year with a total cash balance of $91.5 million, $69.1 million of which was unrestricted cash with another $22.4 million of restricted cash was primarily being reserved for future drilling obligations in Angola. This would only be paid if VAALCO and its partners do not drill the four commitment wells in Block 5, drilling the Kindele exploration well, which we will talk about later, reduces the restricted cash commitment by $5 million. As with the rest of the industry, VAALCO too is coming to grips with managing our business in the new paradigm that's highlighted by the 50% reduction in product price. However, we have enjoyed a successful 2014 with a number of key accomplishments that set us up for significant growth in the future. Unfortunately, the price collapse, of course, caught us all by surprise, which made it difficult to plan our long-term business going forward, but this too shall pass just as previous negative price shocks that passed before. I remain very optimistic about VAALCO's future and our ability to weather the storm. The optimism is, in part, a result of our ability to grow our production profile while at the same time maintaining a relatively strong balance sheet. It is come upon us to protect and preserve our liquidity and doing so we do that through prudent management of our CapEx, OpEx, exploration drilling and our G&A. Between December and January, we integrated no fewer than three times than our 2015 business plan and budget, each one obviously more conservative than the previous estimate. We have taken a hard look at our cost structure and have challenged our team on the ground in Gabon to essentially deliver the same production cost in 2015 that we had in 2014, despite the fact that we have added two additional platforms. We see this as a tall order but we think our team in Gabon is up to the task. We highlighted in November the success of our Etame and SEENT platform construction, transportation, installation and commissioning. And as we look back at full year 2014, we again point to that execution of the project as a flagship example of just what the VAALCO team is capable of achieving. We not only delivered the project with outstanding safety performance, but the platforms were set within one day of the schedule that was agreed to some 18 months earlier. That is world class execution that we are all very proud of. We are pleased to be producing 3,000 barrels a day currently at our new Etame platform owing to the strong performance of our 10-H well, the Etame 10-H. This is what we had anticipated as total production from the drilling of our first two wells despite the fact that our initial well, the Etame 8-H was shut-in after H2S was encountered. Our successful test of the Etame 1-V fault block with the well 10-H has proved our hypothesis of untapped, undrained lower lobe oil in the Gamba interval. That has us very excited. Going forward, we are working with our partners to continue to optimize the well locations and the well count at Etame. At the current strip pricing, our wells at Etame and SEENT offer very acceptable returns. Turning to Angola. VAALCO issued a press release on March 4 announcing that we had spud the first of our Block 5 exploration wells at Kindele post-salt test. We are very excited about this test and are even more excited about the recently processed prestack depth migrated data in the outboard portion of block. The processing, which is being made final this week, has given us a significant uplift in our ability to image both the post-salt and pre-salt needs in the area. We are encouraged about prospecting on Block 5 where we have until November 2017 to drill the three remaining commitment wells. A significant highlight of our 2014 performance was the 2.4 million barrels net reserve addition associated with the Avouma South Tchibala field and the Etame field. These positive revisions consisted of 1.9 million barrels attributable to improved reservoir performance as proved undeveloped reserves. Additionally, we had revisions to our proved undeveloped reserves at the Etame field of approximately 800,000 barrels. These additions were partially offset by a downward revision to the Ebouri field proved undeveloped reserves of 300,000 due to higher cost of developing these reserves rendering these reserves uneconomic. So how has the new low oil price paradigm impacted VAALCO's strategy? Let me say a bit about that. As you all are aware and as we often reported last year, VAALCO has made a significant effort in identifying and evaluating new discovered undeveloped resource opportunities in West Africa, some of which resulted in some advance discussions. At the end of the day, the bid-ask gap remained too wide and thankfully we were unsuccessful. We now have a different focus as it relates to acquisitions, where we are looking to be more opportunistic. Of course, we remain ever more diligent in assessing the quality of the assets to ensure that they are a good fit for VAALCO. Last year, we also said on numerous occasions that we were pressing to move Equatorial Guinea Block P and on Mutamba Iroru block onshore to Gabon forward at an accelerated pace. While we made measurable progress on both of the projects, we have not yet reached a final investment decision on either. We see these projects as longer-term development that will not come online until after 2017. We will be regularly evaluating the project economic at lower oil prices and lower capital costs. We do not have any near-term time constraints under either of these two blocks. For 2014, we finished the year with a capital spend of $92.2 million, which excludes the $11.7 million of exploration dry hole costs. For 2015, we expect lower spending in the range of $65 million to $75 million, including the cost of the Kindele post-salt exploration well currently drilling in Angola. Our 2015 capital also includes the ongoing drilling of our development wells at Etame and SEENT platforms. Additionally, we have budgeted for two contingent wells in the campaign, should we continue to have success and would like to go forward. Looking ahead to 2016, we expect our capital spend to be down from 2015. In 2016, we will also see the production benefits from our 2015 drilling campaign contributing to strong cash flow and to our cash reserves, depending on oil price. Lastly, I want to make everyone aware that for the first time, we will be providing guidance in this call on production, operating expense, capital, DD&A and G&A expense. We hope this information will assist you in better understanding our company as we move forward. In this regard, I just want to share that we expect our net production for 2015 will most likely be in the range between 3,900 and 4,600 barrels of oil per day. Please keep in mind that our production is currently from only eight wells, so we have a measure of risk from unanticipated production or mechanical failures or events that can materially affect our production. As we have done in the past, we will let you know when and if we experience any significant events that affects our production. As far as the first quarter of 2015, we expect to average approximately 4,150 barrels a day. Greg will be providing more on our 2015 guidance elements in his comments. So with that, I will turn it over to Greg to cover the financials in more detail.

Thank you, Steve. I am going to spend the next few minutes, as Steve mentioned, providing an overview of key financial information pertaining to the fourth quarter of 2014 and 2014 full-year results that we reported yesterday in our earnings press release. As mentioned by Steve, the company had adjusted net income of $9,000 or $0.0 per diluted share for the fourth quarter of 2014. The adjusted net income excludes the $98.3 million non-cash impairment charge related to the dramatic decline in the projected oil prices used in the impairment calculation for the Etame, Ebouri and Southeast Etame/North Tchibala fields, all offshore Gabon. Including the impairment charge to reduce carrying value, the fair value fourth quarter 2014 net loss was $98.3 million or a loss of $1.70 per share. This compared to net income of $26.4 million or $0.46 per diluted share in the fourth quarter of 2013. Management uses adjusted net income as a measure of the company's performance relative to other oil and natural gas companies. Other than the impairment, the quarterly financial results were impacted, as Steve mentioned also, by both the oil price collapse that was experienced across the industry and lower sales volumes. As such, revenues of $23.0 million reported for the fourth quarter of 2014 were substantially lower than the $58.3 million revenues reported for the same quarter in 2013. As for the commodity price, the average price we received in the fourth quarter of 2014 was $63.49 per barrel, which was down 42% when compared to the fourth quarter of 2013. Our share of the barrels lifted during the fourth quarter of 2014 of approximately 330,000 barrels in Gabon was 32% lower than in the fourth quarter of 2013. Remember that quarterly revenues are highly impacted by not only the timing but also the size of our crude lifting as we can only sell what we produce, a key measure is to understand our production profile. Production on a gross basis for the three months ended December 31, 2014 was approximately 333,000 net barrels as compared to approximately 405,000 net barrels for the same period in 2013, an 18% decrease. Russ will be providing more information regarding our Gabon operations in just a few minutes. VAALCO's pre-royalty working interest of the inventory aboard the FPSO vessel at December 31, 2014 was approximately 97,000 barrels versus approximately 27000 barrels at December 31, 2013. VAALCO's share of this substantial inventory aboard the FPSO at the end of 2014 gives us a head start to generate oil sales revenues in 2015 on oil that was actually produced last year. For the 2014 year, the company had adjusted net income of $20.8 million or $0.36 per diluted share for the year 2014 before the $98.3 million non-cash impairment charge for offshore Gabon related to projected oil prices. Including the impairment of $98.3 million to reduce the carrying value to fair value, the net loss for full year 2014 was $77.6 million or a loss of $1.36 per share. This compared to net income of $43.1 million or $0.74 per diluted share for the 2013 year. The financial results for the year ended December 31, 2014 were primarily driven by the same three factors, the non-cash impairment charge, lower prices and lower volumes of oil sold. Revenue for the year ended December 31, 2014 of $127.7 million were 25% lower than the $159.3 million of revenue we reported full-year 2013. Our share of the barrels lifted during 2014 totaled approximately 1,351,000 barrels which were 12% lower than 1,544,000 barrels lifted in Gabon in 2013. Now let me move through a few other key financial components for the fourth quarter of 2014. Operating loss was $94.3 million in the fourth quarter 2014 compared to operating income of $36.0 million for the fourth quarter of 2013. Without the impairment charge, operating income would have been $4 million in the fourth quarter of 2014. This operating income was lower because of price and volumes, as I have mentioned before. Production expenses for the 2014 fourth quarter were $10.1 million compared to $8.6 million from the 2013 fourth quarter. The fourth quarter 2014 was higher when compared to the same quarter in 2013, due to deck boiler repairs aboard the FPSO and also drilling launchers related to workovers. Exploration expense for the fourth quarter of 2014 was $0.1 million compared to $2.5 million reported in the fourth quarter of 2013. DD&A for the fourth quarter of 2014 was $4.6 million compared to $5.9 million in the fourth quarter of 2013. The decrease reflects a lower composite DD&A rate for our offshore Gabon assets. DD&A will certainly be at a lower rate in 2015 as a result of the impairment charge taken on our offshore Gabon field. G&A expense for the fourth quarter of 2014 totaled $3.5 million. That was comparable to $3.3 million of G&A in the same period in 2013. Bad debt and other expenses in fourth quarter 2014 was $0.6 million compared to $2.0 million in the fourth quarter of 2013. The quarter four 2014 amount is attributable to an accounts receivable allowance taken to reflect slow repayment by Gabon to reimburse the company for value added taxes or VAT. Although the company is exempt from these taxes, the taxes are first paid to the suppliers of goods and services and then we file for reimbursement from the government. Income tax expenses for the fourth quarter of 2014 were $3.6 million compared to $9.6 million in the same three month period in 2013. The decrease in income taxes reflects the impact of the lower volume of crude lifted during the quarter and prices. Cash and cash equivalents including restricted cash totaled $91.5 million at the end of the fourth quarter of 2014. This compares to $143.7 million at the end of 2013. Capital expenditures of approximately $92.2 million were expended in the year 2014. The borrowing capacity of VAALCO's $55 million credit facility have been impacted by the impairment charge as there is a covenant that prevents us from borrowing amounts that will our debt-to-equity ratio to exceed 60/40. As such, we have estimated the borrowing capacity at the end of 2014 was $25 million. Therefore we estimate we have $10 million of borrowing availability as the company took an initial draw of $15 million in the third quarter of 2014. As mentioned in our last earnings call in November, the company received in October 2014 a provisional audit report related to our Etame Marin block operations from the Gabon General Manager of Taxes. Earlier in 2014, the Gabon Tax Department was charged with finalizing these audits including the incomplete audit of VAALCO on this block operations. As I mentioned last quarter, this was a special industrywide audit of business practices and financial transactions. A formal reply to the draft audit report we submitted to the Gabon Tax Department in February 2015 and we have not received a reply or response as of today and VAALCO continues to believe the audit claims are unfounded. Steve told earlier about the company for the first time providing guidance on production, operating expense, G&A, DD&A and capital expenditures. Steve mentioned that production in 2015 would likely be in the range of 3,900 to 4,600 barrels of oil per day net to VAALCO. I will provide the guidance on the four other components. We believe operating expenses will be in the range of $30 to $33 per barrel, excluding workovers. While on toping of workovers, we have budget for two operations in the Avouma field to replace an inline valve on one well and for replacement of electrical submersible pumps on second well at an approximate combined net cost to VAALCO of $6 million. Moving on to G&A, our guidance for net G&A expense is expected to be in the range of $12.5 million to $15 million in early 2015. Our guidance for DD&A expense is expected to be in the range of $15 to $18 per barrel. This reduction is attributable to the impairment charge taken on the offshore Gabon assets in the fourth quarter of 2014. Capital expenditures in 2015 are expected be in the range of $65 million to $75 million in conjunction with our development well program at the end of fourth quarter of 2014 in Gabon from our two new production platforms and our exploration well that we began drilling in March 2015 in Angola. That concludes my review of VAALCO Energy's fourth quarter and full-year 2014 financial results. I will be pleased to answer any financial questions you may have during the Q&A segment of call. At this time, I would like to turn it over to Russell Scheirman our President and Chief Operating Officer, who will provide you with an operational update.

Thanks, Greg. I would like to start by discussing our Gabon activities and starting offshore to Etame. Production averaged 15,700 barrels per day, which is about 3,800 barrels per day net to VAALCO for the full year of 2014. In the fourth quarter, we were at 14,600 barrels a day, which is just under 3,600 barrels a day net to VAALCO. The decrease in production in the fourth quarter was due to an extended shutdown of the Ebouri 2-H well due to a down hole tubing leak. The well has returned to production in December after a successful wireline intervention that repaired to tubing leak. The Ebouri 2-H well produces just over 2,000 barrels a day. So it was a significant downtime event for us. Year-to-date 2015 production from Etame is averaging around 16,800 barrels per day, which 4,100 barrels a day net. That was as of through last week. As a result of return of the Ebouri well to production and more recently we started up the Etame 10-H well on the new Etame platform, we have been able to increase our production substantially. On an instantaneous basis, today we are currently running just under 18,000 barrels a day. Steve mentioned that the 10-H well was put on production at 3,000 barrels a day. This is a well that's in a separate fault block from the main portion of the Etame field and previously we only had one well in that fault block which was completed at the top of the Gamba, the Etame 7-H well. Before we drilled a lateral to the 10-H well, we drilled a pilot hole to delineate the structure and when we drilled this pilot hole, we confirmed our fear that there are two lobes in the Gamba in this area. The upper wells have indications of water in the basin, but the lower lobe was fully oil saturated. There is a tight streak between the two lobes that's about a 1.5 meter thick. So as a result of these findings, we drilled the 10-H well. We set 9-5/8” casing just through the tight streak and cemented off the upper lobe and then we drilled on lateral in the lower lobe. The result was a water free completion in the lower portion of the Gamba and this opens up the need for additional wells, both in the upper lobe and the lower lobe to drain the Gamba fault block in this area. We are currently drilling a third well into this southern fault block which we expect to have our production next month. This will also be a lower lobe completion in the Gamba. After we finish this well, we plan to moved to the Southeast Etame/ North Tchibala platform to drill into the Southeast Etame and Gamba discovery and then to the North Tchibala Dentale reservoir discovered by [indiscernible] back in 1980s. You may recall at our last conference call in November, we were drilling the 8-H well in the northern portion of the Etame field and as previously announced when we commenced production from this well, it produced H2S, which was not expected. So we shut the well in for safety and marketability reasons after only a 17 hour test. We have now put systems in place to allow us to form an extended well test to determine more accurate level of H2S, which will help us determine the production capabilities of the well. This test will be performed later this month. In addition to the drilling activity loss, we utilize the rig for several workovers at the Etame platform. The Avouma 3-H well has been off-line since August of last year with an ESP failure and we will restore that well to production later this year. We have a second well that should follow 1-C which has one failed pump and it is producing off a defective pump and it's our policy to replace both pumps at the first opportunity in such an instance. This well will most likely be repaired after the Avouma 3-H workover. In the current oil price environment, we are seeking out ways to reduce costs, both for our drilling programs and for ongoing production operations. We have had negotiations with our drilling vendors and have achieved cost savings on our directional, completion, gravel packing and mud services. We have also negotiated lower rate for cementing and logging service. On the production side, we have eliminated a service vessel and are lowering helicopter and fixed lane pipe cost by sharing with other operators. We have also successfully hired local personnel to replace more expensive expat that we utilized for the startup of the two new platforms at Etame and SEENT. We hope to achieve a 15% to 20% reduction in lifting cost through our cost reduction program in 2015. I would like to next move on to how we are addressing the H2S production that we have experienced in three of our wells at Ebouri and Etame. The H2S first appeared in Ebouri in 2012 in two wells and then early last year at the northern portion of the Etame field in the Etame 5-H well which is our highest water cut well. We have confirmed from sample analysis that the origin of the H2S is thermogenic not bacterial as previously thought. Thus the H2S in the basin is probably due to a deep high H2S latent water source connected to the Gamba aquifer presumably to the north of the Ebouri which is where the H2S was first found. So we are working with our partners to address the problem and we have actually completed pre-frontend engineering designs to construct a centralized crude sweetening platform for installation in 2017. At year-end, we began frontend engineering design for that platform and we are moving through this project. But since year end and in light of the decline in oil prices, we are reassessing the scope of the project to evaluate more cost effective alternatives. This could include anything from chemical removal options, construction of a smaller facility on existing structures or the use of mobile or surplus equipment and used structures. So we want to provide a cautionary statement regarding the economics for crude treating at current oil prices. We can't be sure that we will be able to meet our deadline of 2017 or whether the facilities will be built as planned. If we do build a sweetening facility of some scale, it's not known whether or not that facility will be able to treat all of the affected areas of the Etame Marin block. That said, however, we remain committed to finding a cost effective means of removing the H2S from the affected wells. So to summarize for offshore Etame, as Greg mentioned in his guidance, we anticipate growing production to at least 20,000 barrels per day entering into 2016 as a result of new drilling and workover activity at Etame and SEENT. With that, I would just like to give you a brief update on our onshore activities on the Mutamba block. We continue to hold discussions with our partner Total and the Gabon government on how to move this project forward in light of the new petroleum law in Gabon. The government is discussing potential concessions and ways to ensure that the new production sharing contract is in conformance with the law. We remain confident that we will have resolution later this year, such that we can evaluate development options for the N'Gongui oil discovery on the block. Moving to Equatorial Guinea where we have a 31% interest in a development area of Block P offshore at Equatorial Guinea. It's operated by GEPetrol, the national oil company with a 58% interest. The block contains the former Devon discovery known as Venus, located in a water depth of about 800 feet. And towards the end of last year, we submitted a new conceptual work program and budget to the oil ministry to begin front end engineering for the Venus development. We envision initial production of 10,000 to 12,000 gross barrels per day from the field and once the logistics are worked out, we could have first oil and in two to two-and-a-half years from the project sanction. Concurrent with our planning, we are working on a joint operatorship model with GEPetrol, that I mentioned on the last call. The recent drop in oil prices will undoubtedly affect the timing of this project. And we will keep investors informed on subsequent conference calls. We continue to see capital cost declining which may result in this project moving forward more quickly. When we are able to establish production and have an active cost recovery account, we can proceed with the exploration projects which are cost recoverable from production. This will greatly reduce the risk of exposure of these exploration prospects through the consortium. A successful exploration in the project could then be tied back to begin this installation. I would like to wrap up with Angola. After all the significant delays caused by the default of our original partner in Block 5 offshore Angola back in 2009, we have at last, vetted our first prospect, a post-salt test name Kindele using the Transocean Celtic Sea semisubmersible drilling rig. The well is an offset to a discovery made by Conoco 25 years ago tested at 1,100 barrels a day. The well will test an adjacent up from fault block and while this well may not offer the magnitude of reserves found in some Kwanzaa basin pre-salt prospects, it does have unrisked growth recoverable resource potential of 20 to 49 million barrels. Even our availability of shallow water depth position and proximity to shore our threshold for economic liability is reduced compared to the deepwater projects that have been announced by other operators. The well is currently at a depth of about 4,000 feet and is expected to reach the target of about 6,000 feet later this month or early next month. We expect to take about 41 days to drill the well and it will cost an estimated $42 million, which is up from what we had checked before. The additional cost is a result in delays in getting rig. We originally thought we would get the rig back in November. We didn't get it until end of February. On the seismic side, we completed seismic reprocessing over the 2,025 square kilometer 3D data that we have licensed over the block. That seismic will be the basis for the maturing additional prospects on Block 5 to evaluate post-salt structures as well as pre-salt structure similar to ones built by Cobalt which led to their Kwanza basin discoveries. We should have a feel for how many and how large the prospects are towards the middle of this year. As a reminder, our license extends until November 2017. So with that, Steve, I will turn it back to you.

Thanks, Russ. Overall, I would say, we are very pleased with the progress that we made in 2014. We believe that our balance sheet enhances our ability to navigate successfully through this period of lower oil price. We have a growing production profile in 2015, which will significantly benefit us, we believe, in 2016. And right now it looks like our capital program for 2016 will be reduced, certainly from what you have seen at VAALCO in 2014 and 2015. With that any strengthening in oil prices would certainly further enhance our ability to build cash capacity and provide the ability to accelerate opportunities that we talked about earlier, Mutamba, Block P, et cetera. We are anticipating that a good result at Kindele. We hope to be updating you appropriately. We have no other exploration drilling obligations until 2017 and that's right now tentatively the time that we have set to embark on our pre-salt campaign after completing the evaluation of our prestack depth migrated dataset. We also intend to continue evaluating other opportunities specifically discovered undeveloped resource assets that have the potential to expand our footprint, both inside and outside West Africa and significantly add to VAALCO's reserve base. Once again we are excited about our direction as a company. We like where we are headed. We will slug through 2015, which puts us in a position to thrive in 2016 and beyond. With that, we will open on the call up to questions.

[Operator Instructions]. First, from the line of Kyle Rhodes with RBC. Please go ahead.

Hi guys. I appreciate all the color on the guidance. I guess the one thing I was hoping you could speak to would be realized pricing. Fourth quarter was certainly a bit weaker than it has been historically for VAALCO. Is that just a function of higher transport cost for sending crude to Asia? And should we expect that to be the norm going forward? Just any color you could provide there would be helpful.

Yes, Kyle. Thanks for that question. You are right. Our fourth quarter realized price was impacted significantly by the general market for West African crude oil. It was a bit disadvantaged in the fourth quarter. A lot of the cargos that typically would flow from West Africa into Europe had to flow greater distances and as a result, we realized a lower average price for our product. So it has improved, as of late. It had improved, I would say, as of late. So we hope that it continues to improve, but it was a function of primarily of transportation cost.

And I would add that in March the cargo we just recently lifted is going to Europe and the cargo in April is also going to Europe. So we hope to start seeing some improvement.

Great. That's helpful. Then I guess staying offshore to Gabon for a moment, how many development wells are you guys factoring in for your 2015 budget?

We currently have in effect five wells with two contingent wells in our budget. And that's of course in addition to the one well that we drilled last year in the 8-H. So the 2015 budget is seven well total, five firm, two contingent. We also have workovers, two workovers in our budget as well.

Got it and are those contingent wells kind of responsible for the range for the production guidance or maybe what's driving the range of the project guidance?

No. That's it. It's the contributions from each of those wells, 45 to 60 day intervals in bringing a new well on and offsetting that the existing decline from the existing production.

And we also think that we will do a little better than the average of those two numbers. The potential for a workover failed pump or something is what provides the downside of that forecast. So just keep that in mind when you are looking at where we think we are going to be, somewhere north of the average.

Okay. That's helpful and then I guess moving over to Angola, it sounds like you guys are going to hit the primary target next week. When should we expect to get results there? And should we see the flow rates or drill stem test? And then I guess secondarily, is there any secondary objective other than the Kwanza sand you guys are looking out there?

No. The Kwanza is the primary objective and if we find us a big enough [indiscernible] that we choose to test, it would be a couple of weeks after we get there before we have that test.

Any kind of mid, late April type of time frame?

Yes. More like mid.

That's great. And then finally for me, just with regards to your credit facility, is there any way to mend those covenants to get access to the full $65 million or maybe just what you guys are doing on that front?

We are going to be talking with the IFC as we don't think that what has currently happened is really the intention of the facility. We will be working with them to see if we can get an easing of the covenants and perhaps fill that capacity back in.

They have actually, well one of the benefits of dealing with the IFC in addition to some of the cover that we get, political cover, it's one source of funds in one borrower. So it makes these bottle kind of things a lot easier maybe than we would have if we had a facility with multiple lenders.

Got it. Okay. Appreciate it, guys. That's it for me. Thanks.

Thank you, Kyle.

Our next question is from Joe Pratt with Stifel. Please go ahead.

Hi, Steve. If you freeze everything here, including the price of oil, what's the size, is there a cash burn this year?

Yes. We will give the guidance on our capital budget between $65 million and $75 million. We will outspend our cash flow at current prices. But I don't know that we have given that guidance. I get that we have given the operating expenses and we have given the production and we have given you -- when you freeze oil price, you can probably get there pretty closely, but it will be a negative cash year for us certainly.

Okay. Because obviously you have given all the components, I just wonder what the net number was, but I will figure that out, if need be. And then, when Conoco in 1988 made their discovery at Mucanzo, did they ever give out a reserve size estimate?

No, they didn't and really they missed the [indiscernible] on the structure when they drilled that well. They drilled it on 2D and we can get substantially higher on structure to where Conoco was when they found the edge of this thing. So that's what we are looking at with this adjacent fault block. We can get even higher on structure and even though it's a separate fault block, we think they are all in communication, someway, somehow. So we think the oil water contact that they found in the Conoco discovery will probably be the same oil water contact we will see in the other fault block. And so we are hoping to get updip and pull a lot more sand up into the reservoir. We will see.

So they did report, you may notice, but they did report 1,100 barrel oil per day test from that discovery.

Okay and so interpreting for a history major, I think what you are saying is they were somewhat in the right area got 1,100 barrels a day, but you think you are more properly positioned in terms of the geology?

That's correct.

Thank you.

Thank you, Joe.

Our next question is from Glenn Williams with National Securities. Please go ahead.

Hi. Good morning, everyone. Just a few for me. I believe you mentioned that given the strip, you are seeing economic returns at Etame. And I was wondering if you could just speak a bit to what those returns are and how much more downside is this crude prices in regards to the economics?

Yes. The comment we made was specific to the Etame individual well economics and at current strip prices, the wells that we plan to drill are anywhere from, I would say, generally speaking 30% to 80% type returns depending on which well we specifically we are talking. So we have a fairly robust set of opportunity in our development program going forward in terms of individual well economics.

Okay. Thank you. And also I was wondering about the guidance about the guidance you gave and the level of operating expenses in particular around check around and you said $30 to $33 per BOE, but you are also indicating higher production in 2015 as well. So I was just questioning, have you thought about how that will translate in 2016 as well, or something specific to 2015 that is pushing your operating expenses to those levels?

Yes.

The $30 million to $33 million is $30 million to $33 million.

Okay.

Not dollars per barrel.

Okay.

Not sure we said, but it's $30 million to $33 million of total OpEx.

Okay. That's very helpful.

It's going to be in the low-20s on a per barrel basis.

I apologize for all the number in the OpEx table and didn't [indiscernible].

That's fine. That's very helpful actually. And then finally, I was wondering, I may have missed it but if you could maybe speak a bit to, I guess, the upper revision that you had in reserves at South Tchibala as well as Etame?

Yes. We are very excited about that. The bulk of the reserve additions came due to performance revisions. So just improvement in reservoir performance at Avouma and South Tchibala field and at the Etame field, a total of 1.9 million barrels of that add were performance related. And this has been a bit of a repeat story. If you look at VAALCO's reserve adds over the years, because we are in such a high quality reservoir, we have got high flow rate and none of our older wells produce at relatively higher water cut and so when we do our reserve analysis, we are somewhat conservative on the reserve bookings and history will demonstrate that VAALCO has had a history of performance addition. This is probably one of the larger, Glenn, if not the largest, single year, the performance addition that we have had. But the wells just continue to produce. A lot of the wells at Avouma when they have higher water cut. We see the water cuts, that's a rate of incline in water production is lessening. So the well continues to produce more and more oil and that leads to the reserve adds at Avouma and South Tchibala.

Okay. Thank you very much. That's all very helpful. That's all I had.

Thanks, Glenn.

We will next go to Bill Dezellem with Tieton Capital Management. Please go ahead.

Thank you. I actually would like to follow up on your last answer, where the wells are producing less water and more oil as time goes on which seems very counter to the traditional trajectory. Can you talk about what's going on there? Or did I just hear that incorrectly?

Yes, Bill. Let me, I think what I said was, the rate of increase mirrors the water cut. Typically you are right. Water cut increases over time, but we are seeing the rate of increase in some of these wells is decreasing. So the water cut is remaining more constant than what one would have projected a year ago, if you follow me.

Understand. So you had been modeling out higher levels of water in the future and the water growth is not at the same rate and therefore there is less water and more oil, reserves are higher.

Generally, yes. That's one of the contributing factors to the proved undeveloped producing reserve add.

Understood. Okay, great. Thank you. Let me circle back then, the production tests that you had done back in 2010 near the 2-H that you are targeting, what was the production level of that? I don't think I saw or know that number.

Are you talking about Southeast Etame?

I believe that is correct. Yes.

Yes. We didn't actually flow test that well. We have enough experience to know that if we got Gamba paid, that its going to flow or produce 3,000 plus barrels a day from initial rates from a well saturated reservoir.

Understood. And the impairment that you took, does that have any impact at all on your cost account for tax purposes?

No.

Then switching to Angola. You had seismic that you were processing there. Would you talk in a little bit more detail in terms of where that is at and what you have learned so far?

Yes. We have two surveys. We had one that we bought back when we originally got the block in 2006 and we processed that. And that is the one that gave rise to the Kindele prospect that we are drilling now. And there is another post-salt and one pre-salt prospect. And that's in the central portion of the block. There was a second survey that we shot that's in the outboard portion of the block, out in a little bit deeper water. We never could get our partner to join us in purchasing that seismic and after they defaulted we sat and waited until we could get back in business here at the beginning of 2014. So we went ahead and acquired that second survey and the structures out there are pre-salt in nature and we are trying to match them up to look-alikes to what's been published on Cobalt discoveries to see if we have similar type structures. We are just about done with that reprocessing. We should be mapping those structures this next quarter.

And depending on what you find, does that change your drilling, either timeline or location for the next well? Or is that pretty well settled for now and it will be beyond that that you will be impacting?

Yes, I think you know we have to do our drilling and get started late 2016 or early 2017 and whether we accelerate that or not, I think probably will be a function of oil prices and our cash position and those types of things.

Thank you. And then would you please repeat the production numbers that you gave that you are anticipating for the first quarter and for 2015? I simply missed them.

Yes, first quarter was 4,150 barrels a day, net to VAALCO and the production spread, the guidance that we gave for 2015 was between 3,900 net barrels a day and 4,600 net barrels a day.

And my comment was that if we don't have any mechanical issues like a failed ESP or whatever, that we think we can do better than the average of those two numbers.

That is very helpful. And then as you look out into 2016 directionally those numbers should be nicely higher. Is that correct, given the drilling program this year?

Certainly, we should exit the year higher, just based on our current drilling plans, but 2016 can be a function of whether we choose to continue to drill, what happens beyond 2015, which is we really haven't given any guidance on at this point and so -- the numbers we gave assume that we basically continue to drill all year long. Just making no commentary on 2016 in that regard.

Understand. Thank you very much.

Thank you.

Our next question is from Jamie Wilen with Wilen Management. Please go ahead.

Yes. With Sonangol as a partner in Angola, did we ever receive any reimbursement for the monies we put out for our failed partner?

Jamie, hi. Good morning. The original cost, or what we refer to as the back cost which is the cost that was originally owned to us by our initial partner, Interoil, is $7.6 million and we have not, to this point, received reimbursement from Sonangol of that amount. What I can say is that for 2014, Sonangol P&P, our partner is current with regards to their share of the cost that we incurred in 2014. So we are in the process of -- they are paying their way at least to this point.

Okay. That $7.6 million, is that going to be forgotten and forgiven?

No. We don't intend to and we have been told that it's going to be paid to us to date and of course it is not on books. So it has been written off.

Right. Okay. All right. Very good. Thanks fellows.

Thank you, Jamie.

And we got to line of Kelly [ph] with JMP Securities. Please go ahead.

Good morning, gentlemen.

Good morning.

So I am sorry and I may have missed it in your earlier prepared comments as there was a bit of an issue with the dial-in. So I just want to revisit the your currently new and updated, I know you haven't or maybe I missed on the call, but can you tell at least what are your new updated plans or the new updated kind of thought process that you are going through in looking at the [indiscernible] of the H2S impacted crude and how you are revisiting the methodology by shipping away from what the decision you came to in 2014?

Good morning and we apologize for any complications with the dial-in number. We will check into that and see what might have happened. Just real quick at a high-level, because we are not certain how much you might have picked up but essentially our 2015 capital budget will fall between $65 million $75 million. That includes five firm wells and two contingent wells along with two workovers for the Etame ran block. Regarding the H2S, Russell spoke about some things that we have learned. One, we have completed a study of the source of the H2S and we have determined and with very compelling evidence that the H2S that we found at Marin block is thermogenic, which means it's not bacterial. And it's most likely being sourced from a deep hot H2S latent aquifer that is making its way into the Etame main reservoir via the fault to the North near the Ebouri field where the H2S was first discovered. With regards to the project itself, at the end of last year, we began work in earnest on the FEED study, the front-end engineering and design and we are moving forward in hiring engineering companies, but as prices continue to fall, we did a re-evaluation and suspended that engineering work and we are currently working with our partners to look for some lower cost alternative. That could be chemical processing. It could be an element of blending. It could be retrofitting equipments to sit on the existing platform. It could be perhaps purchasing a mobile drilling unit where we can install the equipment on a mobile unit. We don't know yet. But we do know that there is significant reserve remaining and we are committed to figure some way to find out a more cost effective solution to produce that.

Okay. Perfect. Thank you. And then just kind of the back of that thought process, as you work through 2015 and you are working with your partners and the dialogue to determine what the best cost is effectively to recapture those reserves, are you thinking that this is going to the [indiscernible] starts to materialize in the back half of 2015? Or do you see in the next couple of quarters that commentary about what that plan could, what this new revised plan could indeed look like?

Yes. What we are looking to do is to get to the seeking point by at the end of 2015, maybe have -- we are hoping to have a complete evaluation and have chosen an alternative and have been able to propose that to our partners. That's our objective and be able to move forward at that point. But if I answered your question, it was a bit muffled and I wasn't sure if I caught it all.

Okay. No, that's certainly does and I apologize about the audio on my side. That certainly does answer the question and I guess the next layer of question I have is the 2.4 million barrels of PUD reserves that you said in the release this morning. If the plan has not materialized at the end of 2015, is that the point where you might have to look at writing down some or portion of that? Or is that the 2017 timeframe, that you originally targeted for the CSSP coming online is when you have to reevaluate that PUD reserve number?

Yes. The first thing I want to make sure is, because it could be confusing, simply because the numbers are coincidentally the same. The 2.4 million barrels that we added this year, a very, very small fraction like 100,000 barrels of that 2.4 million barrel add are associated with sour crude. So the bulk of the reserve add this year, the vast majority are in fact sweet reserves that are not impacted by any decisions we would make going forward on the sour treating facility. As far as the timing, it's really going to be a function of what -- we are going to add or delete reserves based on the SEP requirements and SEP definitions of what constitutes a proved reserves and we will just have to, at the end of each quarter, evaluate those reserves to make sure that we need to test as promulgated by the SEP to make sure that our reserves accurately reflect our position.

Okay. That's a very helpful incremental clarification there on the sour versus sweet in that number. Thank you.

And one other comment that I would have about that is, because of the way that you do impairments and the nature of how you re-class things, we have essentially taken out for impairment purposes any values associated with crude sweetening. So if there were to be a reserve impairment that would not lead to a further property impairment.

Okay. That was actually my next line of questioning which is related to the impairment this quarter and again I apologize if you have touched on this topic in some of the earlier remarks, but just can you dive into a little bit of the details what the nature of this impairment was? What prompted your auditors to try to capture it within the year-end 2014 reserves, as it seems like many of your E&P peers, both in the U.S. and international waters seem to be rolling out some trying to use the SEP pricing to roll out some of the impairments and for guys they are more likely to materialize throughout 2015. With what you all are capturing in 2014, you feel like you have gotten very much a year ahead of the game for 2015 in terms of what further impairments might be? Are you guys erring pretty much on side of conservatism with this impairment that you take this for?

Impairment calculation is a fairly complicated process. But essentially it takes your historical or carrying value down to fair value. So what have done is, through this process we have reduced the value down to fair value. So with where we are today, if there is a further degradation in prices, that could drive another impairment. It's really not about taking a conservative or aggressive, but on basis that we use for the impairment evaluation, we now have on our books, essentially meeting the criteria we have fair value. I would like to point a little bit here, at the start of your question, maybe I can put a little color on it. The impairment evaluation that we do on a quarterly basis, is performed on a field basis. We operate the offshore Gabon block as a field unit with a shared FPSO facility. The impairment valuation takes into account a number of inputs and allocations including the recent substantial new investment that we have had in platforms and wells and then also importantly taking into account the projected oil prices, which are much lower than they have been in the past. So that being a series of all of that, is why we had a huge impact and a difference in running that n impairment evaluation and very late in the process the auditors came across is, as they were going through this, that we discovered that we had some inaccuracies in our calculations and that's why we took the timeout and brought a team of people in, working all the weekend to make sure that we had the impairment up and calculated and that it could be audited properly by our firm.

One other thing that I would offer on the impairment is, when we sanction the project to install the two platforms, VAALCO and our partners sanctioned the project with three wells on each platform. And when you do impairment testing like at SEENT, for example, the platform is set and you are using only those wells that have been sanctioned. If you recall, we set eight platforms, but only sanctioned three wells on each. So you are limited into what you can use as the forecast of future revenues because you are limited by just those wells that were approved as part of the sanction. And so then you got the oil price happen and you find yourself in an impairment scenario. But the point I am making is, it's our intent to continue to look for opportunities to drill more wells off these platform going forward. Just we weren't able to use any of that in the calculation.

Understood. So if I am remembering that correctly, it sounds like given the fact that you had sanctioned three each, but had also the additional five slots, that the treatment of fair value impairment this quarter did not factor in the potential future value of those five additional slots. Is that reading that correctly?

Yes. We were only able to use those wells that have already been approved and as I said, that doesn't say we are going to have more than three wells each. It's our belief that we will end up with more than three wells on each platform. But all we could use on the impairment test was three wells each.

Understood. Perfect. Thank you. And then just turning to Angola, with another well you said about to reach the target in Kwanza effective potentially within the next week or so. And I did hear Russell's answer in the Q&A about the DSP. How long would you need to line the well thoroughly and get very comfortable with your readings in terms of what the take column looks like before you would feel going out at events and have press release form or talk to us speaking about the Angola reserves publicly? Would you wait for the DSP or would you just go with just an initial account of pay log and announce that?

I think we have announced logging results before we had DSP in the past, if they are significant. So we will have to see what the log looks like. If it's one of those where we can't really tell without a DSP, we may have to wait. So we do a DSP if we choose to do that. But if we were to log substantial amount of oil pay in this well that got us excited, I think we would be in a position to announce or if we were to log a dry hole, we will have to announce that as well.

Thank you. And then finally, in Etame how looking cost savings are materializing, the 15% to 20% that you quoted, can you talk a little bit about what the main component drivers are there? Are there any disproportionate license or lifting cost that you have either seen better cost of materialization or where pricing is staying in and maybe a little stiffer than other components? And then in terms of 15% to 20%, how locked in, what kind of duration do you feel like you could capture that saving?

We have basically four major components to our lifting cost. We have the FPSO, which is by far the largest single cost. Then we have the service vessels that we use to transport personnel back and forth to the platforms and bring supplies to the field. And then we have our aviation component which is fixed wing to get the people down to the airport that's near Etame and then we shuttle them with helicopters and then the final piece is the business of running all these platforms and whatever fuel we are consuming and the personnel that are on the platform. We can't do a whole lot with the FPSO contract. It's a fixed term contract through 2020 with two one-year options. We perhaps could have discussions with them about if we wanted to exercise the option we need to move now. We haven't had those discussions yet. We definitely can do something about the vessels we label to release one, which we were going to have three in the field. We went down to two. On the aviation side, as we lower fuel costs for the helicopters, so we ought to be able to talk to them about passing some of that through to us. We have also figured out some sharing arrangements that we think can last in the longer-term. And then the last piece, which is running the platforms, unfortunately, so far the cost of diesel is mandated by the Gabon government. And they have chose to pass the lower diesel prices on to the consumers at this point, but that maybe coming. And then this business of replacing expats that we used to commission these platforms, as we train up nationals, that will be a long-term development as well.

Perfect. That's great. Thanks very much. And I will release it to the next caller.

Thank you again.

We will go to Robert Arnold with Arnold Corporation. Please go ahead.

Hi guys. With regard to possible exploration expense from the Kindele well, how would that be allocated across the first and second quarters?

If we were to finish the well in the first quarter, it would all be at the first quarter, depending on what we end up doing to test the well and determine whether it's something that we think is productive or non-productive, some small piece could get second quarter. but we would probably know that by the time we are filing the -- if we don't know the results of the well by the end of first quarter, then it might all hit the second quarter. But I think by the time we had to file in the second quarter, we will know when we will be able to make the allocation.

But essentially we have at this point, that well has recorded CapEx and at the end of the month, we will figure out the cost at that point, as we make the CapEx investment for the first quarter, the remaining CapEx will find it's way into the second quarter and as Russell mentioned, if it turns out that it is a dry hole and ends up being expensed, we go back and we would expense the portion incurred in the first quarter.

Yes. Got it. But the portion that was expended during the first quarter would be allocated in the first quarter.

Yes. And the majority of the well is being drilled in the first quarter.

Got it. Yes. And should that be a successful effort, how long to get it on production?

I think in terms of how soon we can get it on production, I don't know but I think SEP will release us the hole for five years or longer in remote areas. But how soon we will we get on production, it's going to depend on what we find.

The one thing I would mention is that we do have a number of other post-salt leads in the area and part of our thinking here at Kindele is to test our hypothesis, test this one prospect and you could see is Kindele being made part of a broader development with either other post-salt discoveries or a pre-salt discovery.

And last question, what are you going to do onshore with your discovery that Etame?

The onshore discovery at Gabon?

Yes.

Yes. We are working diligently with our partner and the government to clean up some legal questions that this new petroleum law brought into play. And as soon as we can get that sorted out and it's just is frustrating how long some of these things takes sometimes, then we can get the production sharing contract put in place and begin to move forward to get a development area assigned to it and work to file a development plan. Typically development plan gets filed within a year after you get the production sharing contract together. And then you have got some time beyond that to actually do the work and get the field on production. And we will have to watch oil prices pretty carefully too.

As well as capital costs as they are falling but they tend to life [ph].

That's it for me. Thanks.

Thank you, Robert.

We will go to Neil Nelson with NNI. Please go ahead.

Just one for me, current events with Harvest Natural Resources and their potential delisting, is there any interest in picking up the Dussafu concession on the wells that are pretty discovered wells that they made but have never produced?

As part of our 2014 effort to find a suitable discovered undeveloped resource opportunity, we scoured West Africa from Cote d'Ivoire to Namibia looking for a good fit and looked at a number of different asset opportunities. As I said earlier, some of our discussions were fairly advanced and we were not successful. But we are not liberty to talk about which of those assets they were or what conversations we had. So I appreciate it but we looked at everything that we thought made sense for us.

Okay and with regards to the evolution of the Angola prospect, from an economic standpoint, can the post-salt wells, are they at a depth that could be produced subsea without a platform?

Yes. That is an option. We found depending on the size of the accumulation, it maybe more economic to develop subsea wells than an FPSO, mostly as a fixed platform. So that is certainly a viable option.

Which will reduce both capital costs and accelerate your ability from a time to positive cash flow, right, to turn the investment on the drilling side?

It could. Depending on the size and the number of wells you are going to drill. Typically if you have less than three wells, it's to your advantage to use subsea completion than an FPSO. If you get to more than three wells, it's a break over point where it makes no sense to set a fixed platform and drill dry sheet from the fixed platform. So it just depends on the size of the development. But generally speaking, yes, you could potentially accelerate the development that way.

Okay. That answers my question. Thank you very much.

And out final question will be from the line of Dave Banster [ph] a private investor. Please go ahead.

Just as it relates to timeline for the calling number problem, your [indiscernible] had the right number ending at 93 and the release had ending in 92. So, it's not really a big deal. We are all kind of confused here but on your last call you used some really good information when you talked about the difficulty and some times it's easy when looking at a small company as from a big one to find these things out. You said two of your liftings, one went to Japan and one went to Australia and you consolidate three more across Europe. I am just wondering, during that period, three of your liftings were understand 300,000 and then you had one at 700,000 less, it was 800,000. Now that we have March and April are both going, are those going to be lower in the 700,000 to 800,000 area and how does that affect pricing?

Yes. They will be the larger liftings. The smaller ones we co-load it with another local current other local current or local crude. But these, the March and the April liftings are both full Suezmax 725,000 to 750,000 barrel liftings, both of which are going to Europe.

Okay. Thank you.

And I will turn it back to presenters for any closing comments.

Yes. Again, apologies to everyone for having to move the conference call, first off and secondly for apparently having a transposition on the number. We apologize for that. But just overall, I just want to summarize by saying that we remain enthusiastic about our current circumstances with variable debt and cash on the balance sheet and opportunities set in front of us to grow our production at the Etame Marin block throughout 2015. We feel this puts us in a great position going forward to 2016 and beyond and you supplement that with the fact that we have an exploration well, a long-awaited exploration well. We have been in this since 2006. So that could really impact the company in a meaningful way and it is an exciting time for us. So we do appreciate everyone's interest. We appreciate everyone's question and with that we will end the call.

Ladies and gentlemen, that does conclude your conference for today. Thank you for your participation. You may now disconnect.