VAALCO Energy Inc (EGY) 2013 Q4 法說會逐字稿

Ladies and gentlemen, thank you for standing by, and welcome to the VAALCO Energy end of the year 2013 earnings report.

(Operator Instructions)

And as a reminder, today's call is being recorded. I'll now turn the conference over to the Chief Executive Officer, Mr. Steve Guidry. Please go ahead, sir.

Thank you, John, and welcome, everyone to VAALCO Energy's fourth-quarter 2013 and full-year 2013 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 without further delay, I'll briefly hand it over to Greg to cover our cautionary statement.

Great, thank you, Steve. 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 activities, events or developments that VAALCO expects, believes, 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 file with the Securities and Exchange Commission, the latest of which was the 2013 Form 10-K that was filed with the Commission on March 13, 2014. Steve, back to you.

Thank you, Greg. Having just completed my first four months as CEO of VAALCO Energy, I must say that my excitement, my enthusiasm, and optimism about the direction of our Company and our prospect for future growth continues to rise. We're putting that excitement and that enthusiasm to work and have accelerated the pace of play in delivering on our plans for 2014 and beyond, addressing head-on the obstacles and impediments that have slowed our progress in the past.

I'm going to spend a little time talking about our fourth-quarter and full-year 2013 results at a very high level. Then I'll ask Greg and Russ to follow up with a more detailed discussion.

Before I start, though, I'd like to talk just a bit about our strategy and the opportunities that we see for VAALCO. As most of you are already aware, VAALCO's Etame Marin block in Gabon is the backbone of the Company's operations, and continues to generate strong reliable cash flow, which provides the currency necessary to fund our growth opportunities.

Currently, our opportunities for longer-term growth lie in the exploration prospects in Equatorial Guinea Block P and Angola Block 5, where we have made significant progress over the last several months. We believe this represents outstanding opportunity for significant value creation for our shareholders.

However, to better balance our reliance on higher-risk, higher-reward exploration, VAALCO is looking to make the right discovered resource acquisition, which is to say we seek to acquire an asset that has had a substantial non-producing discovery on it that we can readily develop and bring to market in a relatively short order, and which would then provide greater certainty to our production, reserve, and cash flow growth. We are currently scouring west Africa in search of that right opportunity.

The development of a discovered resource in west Africa matches our proven competency and skill set. VAALCO has demonstrated in the past the ability to repeatedly exploit, develop and bring to market numerous discoveries on the Etame block. We are committed to repeat that success elsewhere.

A bit about the results, in terms of the fourth quarter 2013, VAALCO reported net income of $26.4 million, or $0.46 per diluted share. That is compared to a net loss of $18.9 million, or $0.33 per diluted share for the comparable period in 2012. For the full-year 2013, we reported record net income of $43.1 million or $0.74 per diluted share, compared to net income of $600,000 or $0.01 per diluted share for 2012.

As I mentioned earlier, we've had a wide range of opportunities within our portfolio, and we have continued to make progress on our growth projects in equatorial Guinea and Angola. In particular, we expect to drill four exploration wells by the end of 2015. This is an aggressive drilling program for these two areas, and, of course, we will continue to have capital obligations in Gabon with our expansion project.

We recognize that in order to fund our drilling program while maintaining our traditional balance sheet flexibility, we needed to take on leverage, so in February of this year, VAALCO announced that we executed a loan agreement with the International Finance Corporation for a $65 million reserve base loan facility secured by the assets of the Company's Gabon subsidiary. We intend to use these proceeds of the loan facility to support our Gabon development program. This in turn frees up the cash generated from the block for use on opportunities outside of the Etame field and the Etame block.

With that, I'll pass the call to Greg to discuss our financial results in further detail.

Thanks, Steve. I'm going to spend the next few minutes reviewing the key financial information for the fourth quarter of 2013, as well as 2013 full-year results. As you've probably seen in our press release or the 10-K that we filed yesterday, VAALCO finished the year with a strong quarter, and reported record net income for calendar year 2013.

As Steve mentioned, the Company reported net income of $26.4 million for the fourth quarter of 2013. This compared to a net loss attributable to VAALCO of nearly $19 million in the fourth quarter of 2012.

The strong net income reported for the fourth quarter of 2013, when compared to the same period in 2012, comes down to three factors: VAALCO's share of the oil liftings from our Gabon operations, income taxes paid in Gabon and the impact of prior-year exploration efforts that negatively impacted the fourth quarter of 2012.

Our share of the barrels of oil lifted during the fourth quarter of 2013 in Gabon was 10% higher than our share of oil liftings sold during the same period in 2012, resulting in a revenue increase of nearly $5 million. However, a larger factor was the impact of income taxes paid in Gabon.

With the active rig program and the construction costs for the two new platforms being built in Louisiana, we kept the cost account at a high level throughout the year. The impact of this is that we have a much higher percentage of the oil sold during the fourth quarter of 2013, compared to the fourth quarter of 2012 being allocated as cost oil barrels, which do not bear income tax.

Our production sharing contract provides for up to 70% of the oil lifting value to be applied to cost recovery, or in other words, the government of Gabon receives income taxes on a minimum of 30% of the lifting value, which is the profit oil component. With the high level of capital investment, the amount of tax paid in the fourth quarter of 2013 was $11.4 million less than the amount paid in the fourth quarter of 2012.

The last factor explaining the variance between the two comparative quarters was the impact of dry hole expenses incurred in the US in the 2012 period. Exploration expense recorded in the fourth quarter of 2013 was $30 million less than the same period in 2012.

Steve also mentioned that for the year, VAALCO reported record net income of $43.1 million in the fourth quarter -- or for the full year 2013, compared to $0.6 million that we recorded for calendar year 2012. And again, the factors that comprise the $42.5 million increase in net income year over year are primarily due to significantly lower income taxes paid in Gabon, and lower exploration expenses recorded in 2013. Breaking it down a bit further, we did have an 11% decrease in our share of oil barrels lifted in Gabon in 2013, compared to 2012, and coupled with a 2.5% average price per barrel decrease, 2013 versus 2012, this resulted in approximately $25 million less in revenue for the year.

So that begs the question, well, where did the increase in net income come from? And again, the answer is primarily attributable to the difference in the amount of income tax that we paid in Gabon in 2013, versus 2012.

Previously, I mentioned that had we kept the cost account at a high level throughout 2013. Therefore the reason for the lower taxes is a function of the expenses we incur and the capital investments we make, which drives the amount of barrels allocated as cost oil instead of profit oil barrels, and the latter of course being the ones that bear income taxes.

We paid approximately $48 million less in Gabonese income taxes in 2013 compared to 2012. The other main factor impacting the year-to-year variance in net income is that exploration expenses were approximately $17 million lower in 2013 when compared to 2012. And the lower amount of exploration expenses in 2013 is due to a lesser amount of expense recorded for unsuccessful exploration wells.

Next, I'm going to talk a little bit more about the details for the quarter. Operating income was $36 million for the fourth quarter of 2013, compared to $2.3 million for the fourth quarter of 2012. Crude oil production from the Etame, Avouma, South Tchibala and Ebouri fields averaged a bit over 18,000 gross barrels of oil per day in the fourth quarter of 2013, compared to an average of approximately 16,800 gross barrels of oil per day during the same period in 2012, a 7% increase.

The reason for the increase quarter-versus-quarter was the impact of a five-day production shut-in, in October of 2012, to conduct routine periodic maintenance on the FPSO vessel. Production expenses for the 2013 fourth quarter were $8.6 million, nearly identical to the $8.7 million amount recorded in the fourth quarter of 2012. Exploration expense for the fourth quarter of 2013 totaled $2.5 million, compared to $36 million of exploration expense recorded in the fourth quarter of 2012.

The main component of the 2013 fourth-quarter spend was the write-off of drilling costs incurred in 2013 on the unsuccessful Dimba well, which we previously announced. We will record an additional amount of dry hole cost for this well in the first quarter of 2014 in the amount of $11.2 million, VAALCO's share of the well. The 2012 exploration expense amount included dry hole costs for four wells that were drilled in the United States.

The income tax expenses for the fourth quarter of 2013 were $9.6 million, compared to $21.1 million in the 2012 fourth quarter. And as we know by now, the decrease in income taxes reflects the impact of the highest cost account, which results in a higher percentage of barrels allocated as cost oil barrels versus profit oil barrels. The cost oil benefit was partially offset by the impact of the $5 million of increased revenue in Q4 2013, versus Q4 2012.

Cash and cash equivalents, including restricted cash, totaled $143.7 million at the end of the fourth quarter of 2013. The Company did not have any long-term debt as of the end of 2013.

As previously announced, and as Steve mentioned, the Company finalized a $65 million revolving credit facility with the ISD in the first quarter of 2014. The credit facility is available to be used for capital investments in Gabon, and to date, we have not drawn down any amounts on the credit revolver.

Coupled with the cash position at the end of the year, the Company has ready access to significant capital resources. VAALCO's capital expenditure budget for 2014 is approximately $117 million. Lastly, although there was no repurchase activity in the fourth quarter of 2013, the Company repurchased approximately 1.8 million shares of stock in 2013, at an average price of $6.49 per share, totaling $11.5 million.

Turning to 2014, we will be recording in the first quarter the additional dry hole cost of the Dimba well, as I mentioned earlier, and we expect to benefit from low income taxes to be paid in Gabon throughout 2014, resulting from the investments we are making, pertaining to the construction and installation of the two new platforms, as well as drilling rig costs. Additionally, we have recently invoiced Sonangol P&P, our new working interest owner in Block 5 Angola for over $8 million, pertaining to unpaid partner share of costs, dating back to 2009. Once this cash is received, this amount will be recorded as net income in our 2014 financials.

With that, that concludes my review of VAALCO Energy Inc's fourth-quarter and full-year 2013 financials. Russell Scheirman, our President and Chief Operating Officer, is up next to provide you with an operational update.

Thanks, Greg. I'd like to update everyone on our ongoing activities at Etame, including the status of the two additional platforms that are being constructed, our onshore Gabon Mutamba project, Equatorial Guinea, and our Angola activity.

Since our last call, we drilled the Dimba exploration prospect, which despite an advantaged structural position and hydrocarbon shows was non-commercial, due to thinning of the Gamba reservoir over the prospect. The rig is currently on the Avouma platform, where it is performing a pump change on Avouma 2H well.

We were able to secure a third slot from the [Venrenish] well rig, so that after the Avouma 2H workover, we will follow on with the redrilling of the south Tchibala 1H well, which experienced a casing failure a few years back, that we didn't realize it was a casing failure until we tried to change out the pumps last year. The successful redrilling of the reservoir section will add a fourth producer to the Avouma South Tchibala platform complex, and should help to mitigate field deadline while we await the installation of the two new platforms, and the six new development wells in the Etame area.

As previously announced, we will be commencing a five to six day maintenance shut down on the FPSO this weekend. In connection with the shutdown, we'll also be performing some diving work to ready pole lines for the future platform expansions. So with the workover activity and the shutdown, it appears now that our next lifting will be in April.

The two platforms for the Etame and Southeast Etame/North Tchibala developments remain on schedule, with the fabrication of the two platforms at Gulf Island Fabricators in Houma, Louisiana. As I described before, one platform will be installed at the Etame field to add infill wells to more fully develop that field. We anticipate drilling three wells initially, and up to five wells off this platform over its life.

The second production platform will develop the Southeast Etame discovery and the North Tchibala field. The North Tchibala wells will be completed in the Dentale formation, which opens a new reservoir for offshore Gabon. The Dentale, if successfully produced on trend with our offshore fields onshore.

North Tchibala field will also expose us to a gas resource which will be valuable as a fuel source for the Etame complex in the future, eliminating the need to use diesel for power generation. The platforms will be installed by EMAS, which is a company based in Singapore. They built a new installation vessel, with a 3,000 ton lifting capacity, to install both the jackets and the decks.

The vessel is currently in China, where the crane is being installed. It's due to arrive in the Etame area to [stress the two] jackets in June of this year. It will then go off for some retrofit work, and then will return in September to install the two decks onto the jackets.

EMAS will also have a second vessel that they will utilize for the pipe laying project to connect the platforms to the FPSO, we'll be re-routing some existing flow lines, and laying hard pipe for the oil and fuel gas production. The work actually started this week with the arrival of the EMAS expeditor, which has all the pipe for the pipelines pre-reeled onto the vessel.

Each platform represents about a $40 million net investment for VAALCO, plus the cost of wells, which run about $7.5 million each, net to VAALCO. With this project, our goal is for these two platforms to allow us to maintain production near to or above 20,000 barrels per day, well into 2016.

I'll mention that front-end engineering design works continues for a sweetening facility for the Ebouri wells, which began to produce H2S last year. We expect the sweetening project to reach final investment decision this year, with the facilities to be in place in late 2016, to come online in early 2017.

With that I'd like to move onshore, Gabon to Mutamba. We field an exploitation area around the Mutamba block N'Gongui discovery that we announced last year. As Steve mentioned, we remain in discussions with the Gabonese government over the approval of this development area, relating to some new fees they are seeking to impose on our consortium.

The Gabon's government focus on their deep water licensing ground has limited the availability of the administration to finalize the negotiation. However, we hope to include it in the near term, such that we could file a development plan in 2014.

We envision tieing the discovery back to the Atora field, which is a Total-operated field about 5 miles from N'Gongui. This would allow us access to a pipeline that goes to the coast, where there's a lifting facility. As part of the negotiation for the development area, we're also negotiating an extension to the exploration area, with an initial three-year term. So that's it for Gabon.

In Equatorial Guinea, we own a 31% interest in the provisional development area of Block P offshore Equatorial Guinea. This block is operated by GEPetrol, which is the national oil company, which has a 58.4% interest, and there are two other partners with about 5% each.

The block contains a 2005 Devon discovery known as the Venus field, which encountered a 300-foot oil column in a channel sand sequence. The discovery lies in an area where the water depth is about 800 feet.

There are other channels on the block that we plan to explore, and we have a two-well drilling program planned, once we work out arrangement with GEPetrol how to share operator-ship. We proposed a joint operator-ship model with GEPetrol, which has been well-received by GEPetrol in the Ministry of Mines and Energy, and we're currently designing the organization to begin the planning process and acquisition of long lead time items for the drilling program.

So finally moving to Angola, we are operating under a two-year extension until November 30, 2014 on our acreage there. We continue to move forward on testing our exciting exploration potential on block 5. As we reported last quarter, after years of pressing for resolution of the partner issue, we were happy to learn that Sonangol E&P assigned the defaulted 40% interest to Sonangol P&P.

We've held technical workshops with our new partner and have successfully on-boarded them. We've also met with the highest authorities at Sonangol EP, our concessionaire, and have established several options available to us that will allow us to benefit from the recently-licensed seismic and drill our wells at a logical and more appropriate time.

While not all of our options include the drilling of a well in 2014, we're putting ourselves in a position to do so, having received a number of bids through our February rig tender process. We will ensure that we are in a position to deliver on our commitments before the end of the extended primary term.

With that, Steve, I'll turn it back to you.

Thanks, Russ. What I'd like to do is just to summarize maybe in conclusion some of the key elements that I think you heard us talk about this morning. First, I should say, I'm very pleased with the progress that we've made in 2013, and in particular, very proud to be able to report record net income for the Company.

We've certainly have committed to redoubling our efforts to progress our exploration and development programs, as you heard in Equatorial Guinea, Gabon and Angola. Just a side note, between Russell, Greg and myself, over the last four months, we've made eight trips to West Africa, all designed to move our projects forward. I hope you see we're very serious about progress and about delivery.

We've had a wide range of opportunities within our portfolio, as we talked about, and so that of course is what drove us to put in place the credit facility, that now gives us significantly more financial flexibility. We certainly intend to continue to look for new opportunities, as I mentioned, specifically the discovered resource opportunities, that will help to expand our footprint in West Africa and significantly add to our reserve base.

But the things that we've done here most recently haven't just focused on project progress. We've also taken steps to enhance our VAALCO team performance as well, and during my early tenure here, I've worked closely with the Board and with the management team to redesign the compensation system to one that is much more directly tied to shareholder value creation.

We have established a series of KPIs and individual goals and objectives that align the efforts of all VAALCO employees with the stated objectives, and the deliverables of the Company. So, again, we're very excited about the direction that we've taken here at VAALCO, and we are committed to continuing to accelerate the pace of play in delivering on our plans for 2014, and for the period beyond that as well.

So this concludes our opening remarks. At this point, I will turn it back over to John.

(Operator Instructions)

Leo Mariani, RBC.

You talked about some production downtime here -- five to six days to be shutting things down -- pushing the lifting to April. In a recent press release, you guys also said there could be some other downtime in the FPSO later this year to have something to do with installation of fire prevention and sprinkler systems. Can you give us some more detail -- timing of when you expect that, and length of shutdown for that?

It would probably be late third quarter, or early fourth quarter, and it would probably involve a three- to five-day shutdown, depending on how much of the work can be pre-done. We would try and tie it in with any shut-down time that would be required to get the new platforms up and running.

There's some things that have to get tied in, and some times when we'd have to have things shut down, so we try and work them all together to minimize it, and get it all done at once. That's what we're doing on this shutdown right now is we're pre-positioning flow lines and things, so that we do that while we're shutting down for maintenance, rather than having to do that as a follow on.

Leo, I might mention the FPSO shut down that is coming up is really a deferral of the one scheduled for the fourth quarter of last year, but we deferred it, so that we could wrap up other projects and get the biggest bang for our buck. The additional FPSO shutdown coming up in October is really the one that we had scheduled for doing a number of activities annually, coming up. It's not like we're doing more frequent ones, and we'll have to wait and see whether the one actually occurs in the fourth quarter this year or not.

Okay. I guess with respect to those shutdowns, are you guys actually -- I'm assuming at that point you're shutting in the wells -- all the production wells?

Yes, the wells are all shut in. We have to flush the pipelines because of the wax issue. So, that's what we're doing right now, actually, is flushing the lines.

And then, once all that oil is flushed out of the lines, we can shut down the FPSO systems, and they can -- they're replacing valves and sections of pipe where the NDT shows there have been corrosion, this type of thing, just to keep the ship up and running.

Okay. And I guess, jumping over to capital for the year, you guys talk about your $117-million budget. Maybe you can kind of give us a little bit more detail around that. Just trying to figure out how much would be spent in the Etame concession, which I guess clearly you get to deduct your costs there.

And then how much of that do you think may potentially be deferred into 2015? I'm assuming you've got some Angola CapEx in there that may or may not got spent. Can you just talk us through what that number could be on the lower end on the CapEx, and what that Etame spend is?

The total Etame spend is about $75 million of the $117-million total. The balance is roughly $30 million in Angola, and $12 million in EG, so those are the ones that could slip and slide around.

We basically assumed that at least one well would get drilled in each area. Maybe we drill two in EG and none in Angola, or maybe we drill one in Angola and EG slips, we're not quite certain, but that's the breakdown of the $117 million.

Okay. And that's helpful.

And I guess, realistically, just to make sure it's clear. Are you guys pushing with your partner in Angola to get an extension, and then try to drill the wells in 2015? Is that your ideal situation?

Yes, what we've talked about there, Leo, is that we bought some additional seismic, about 1,050 kilometers of seismic that's out -- a little further out in the deeper portion of the block. We see on 2D some of these deep-seated carbonate-like structures that Cobalt has been drilling. So, we went ahead and bought the 3D, and we're merging that with our existing 3D that's over the post-salt prospects on our block and the one pre-salt that we have in shallow water. And we're reprocessing all of that all the way to pre-stack depth migration.

And that process is going to take most of the year, so if -- and Sonangol is aware of this, as is the concessionaire. The conversations we're having is: Do we really want to go drill two shallow-water prospects when there's this big stuff out in the deeper section that we -- that we're trying to image with the new seismic processing? And they understand the logic of that, so we just have to work out what we'll do; whether we'll hold off and drill both wells back to back, or whether we'll drill one now and they'll give us an extension for one later, or whether they'll give us an extension for both wells.

And I've been over there, and met with the President of the concessionaire, and it was a pretty relaxed conversation, and I think we'll work something out. I may be going over there again in the next few weeks, to see if we can. And we're also holding another workshop with Sonangol P&P in Luanda at the end of this month, so we'll see how it all shakes out.

Okay. And with respect to comments on acquisitions that you guys have made here, you spoke about scouring west Africa for deals here. Just any comment on -- if you're seeing anything out there that you think is fitting of the acquisition model you guys are planning? Is that something you think can happen in the next couple of months, or do you think it's more realistic, it may take the balance of the year or longer on an acquisition here?

Yes, Leo, this is Steve. We see several opportunities up and down the coast, some better fit than others, obviously, but we continue to work through that. We have engaged with our Board. We've talked about some of the options that are out there.

It's tough for me to comment on whether or not we think something will actually happen in the near term. It's going to be a function of the quality of the opportunity, and our appetite for it. We certainly continue to look. I would say it's -- garners a lot of attention by the management team here, and certainly our technical team. But at the end of the day, we won't be able to say for sure until we work through all the details.

Okay. And I guess, just lastly, on Mutamba. It sounds like that's been a little slow going here. You talked about desire to kind of get a development plan filed sometime later this year. Is there any update on when you actually might think you get first production here? Is it still slated for 2016 in you-all's mind?

Yes.

Okay. Thanks.

Eric Anderson, Hartford Financial.

Following up on Leo's question on the purchase of a discovered but undeveloped asset out there -- what's the approximate range of sizes that you folks are looking at, ballpark? I don't want to pin you down, but what's the range you're looking at in terms of the capital cost?

It's a fairly broad range. For us, anything from -- in the $50-million to $75-million acquisition range, and a development cost in the $100-million to $200-million range is what would be our sweet spot. We certainly can do -- positioned to do smaller acquisitions, and we could maybe do something larger, but it's -- that would be what I would describe as our sweet spot.

And this is something that you would do by yourself or maybe in partnership with other companies that are out there?

Both. It just depends on the opportunity -- something that we could either do ourselves or partner with. It just depends on the individual circumstance really.

Would you hope to have something done this year in that regard, or is it just something you're going to be taking your time on, and be careful with?

Yes, we will take our time, and we certainly will be careful. And yes, we would like to get it done this year, but as I said earlier, it's going to depend on the quality of the opportunity that we see.

All right. If I could ask a question about the Dimba well -- given that you had hydrocarbon shows in the well, are you thinking of possibly re-drilling that maybe lower on the structure?

We actually did side track that well down dip. Every well that's been drilled on the Etame block has had good Gamba sandstone, and so, then we go drill one and we find 10 feet of Gamba and it's tight on the top. We sidetracked it down dip. We found better reservoir, but we also found an old water contact that just made it too small.

So, the structure was there. If the sand had been the thickness that it is everywhere else on the block, it would have worked. But something in the way it was laid down caused that to be a sand-starved region, and that was a big surprise to us. And that was the reason that -- so, we've already done just what you suggested.

Okay. Now, were you using 3D seismic there?

We were. And the 3D seismic -- you can see the base of the salt, but you can't really determine the thickness of the Gamba. So, you have to rely on other wells that have been drilled to the north and south and east of there, that all have anywhere from 13 to 20 meters of sand in them, and then we come in at 3 meters of sand. It was just a total surprise.

And how would you characterize the lower objective that was the bail-out target there that you were going down deeper to?

We just did not see significant, good sand development down there, so the rock that we drilled was not of reservoir quality. And that, we knew, was the risk all along on that prospect.

Okay. But it would have been the upper section that would have made it appealing, even if it were the normal 10 feet in thickness?

Correct. The Gamba -- if the Gamba had worked, we would have had a development. The other was a deep-seated structure, and it had some characteristics that looked like some wells that were six or eight miles away that had sands in them. And so, the thought process was: Drill the Gamba, and then just keep going and see if those sands develop like they did in those wells six or eight miles away, where, by the way, they tested oil. And we could see a structure, but we just didn't get the sand development that we were hoping for.

Okay. And lastly, if I could ask: What are the types of day rates that you're finding out there in terms of the types of rigs that you're possibly in the market for? Prices softening a little bit, or how would you characterize the market?

It's not bad. I think the rig rate we have for the Ben Rinnes is in the low-$100,000s.

The rig rates that were bid for Angola were -- which is a semi -- were within what we had budgeted. So, there are a few rigs available out there. The rigs we're looking at for our expansion project are probably a little more sophisticated than the Ben Rinnes rig. And so, will probably command middle-$100,000s or below-middle-$100,000s kind of a rig rate range.

Okay. Appreciate you taking my questions.

Chris McDougall, Westlake Securities.

Thanks for the thorough update and strong results. Going back to last quarter, you were thinking that the production for Etame would be up above 20,000 barrels a day by first half of 2015. Is that still the case?

Yes, this is Steve, Chris. We'll get the platform set, in 2014. Our rig program would start right at the end of 2014. And then our rig program for the new development would be throughout the first three-fourths of 2015. So, you'll see production increasing in increments throughout that period.

Okay. And so, by the end of first-half 2015, a 20,000-barrel-a-day exit rate is a reasonable model?

Yes.

Great, thanks. And then one last thing. I think Leo and everybody else had covered most of the big items, but just -- you do have the stock repurchase plan that you're about halfway through on the year. Have there been any changes, or changes of the rate of executing on that, or is that on hold?

It remains an option for us. We continue to see that as a potential option, but we don't have any specific plans as it stands. We're just continuing to look for the right opportunity without really an obligation, but with knowing that it's an option available to us.

Okay. Great. Well, we look forward to seeing the progress into the next year. Thanks.

(Operator Instructions)

Joe Pratt, WFC Asset Management.

I didn't exactly catch when you expected first production out of Mutamba?

2016.

2016?

Yes.

Okay. And secondly, how did the sands in the [DAS-approved] block next door compare to the sands that Harvest discovered, compare to the sands in the Etame 8 block?

Well, from what we know, they're finding hydrocarbons in Gamba, and in the Dentale, which is the same as what we have in Etame. We have never produced the Dentale. We are going to try and produce the Dentale. We expect to produce the Dentale.

It's been tested at rates of like 2,500 barrels a day back in the 1980s. So, with this new platform, we are going to try and learn about the Dentale.

The issue with the Dentale is we don't know about connectivity and water drive and some of those things, so we want to learn from that. The good news is that that same platform will also be drilling wells into the Gamba in the southeast Etame discovery, so we kind of have a fallback if the Dentale isn't as good as we hope it will be. But my understanding is the regime down there to the south -- it's a continuation of the Gamba Dentale plays.

Okay. Thank you very much.

[Neil Nelson, NNI].

Could you discuss the Avouma well with the damaged casing, and when do you think that will be back on production, when you re-drill it, and will you continue to operate that well?

Yes, we should be done with the workover on the 2H well end of next week, and put that well back on production. I don't know whether we mentioned, but that well -- actually, the second pump on that well went down about 10 days before we were ready to get on it, which was disappointing. We were hoping to be able to get on it before the second pump went down. But anyway, we're on it now, and we should have it back on production sometime end of next week, early the following.

We'll immediately slide over to the Tchibala 1H well. It's about a 30-day workover. Basically, we'll be side-tracking out of the -- out beneath the 13 3/8-inch casing. We'll cut and pull some of the 9 5/8 to give us a window, and we'll side track out and just re-land the well and set casing and pumps, and it should be a perfectly good well.

We're going to use a little heavier 9 5/8 casing this time. We don't think it was actually the casing that parted. It was a coupling that may have parted, and that may be due to some sort of stress from the salt. But we should be able to get a good 1,500-barrel-a-day well back, that has been down now for several years.

Neil, this is Steve. I might just, for a minute, brag about our technical team. The fact that in the Etame field we run tandem submersible pumps for this very reason. And the well that we're currently working over, the first pump failed some nine months ago. We've been able to produce that well for nine months uninterrupted.

Unfortunately, as Russ points out, it went down 10 days before where the rig showed up. But if we hadn't applied that technology of running dual tandem pumps in this well, we could have likely had the well down for nine months before the rig was available. Credit to the technical team for stepping out and utilizing an approach to producing these wells that's not often utilized by other operators.

In the case of the Etame concession, where you have subsea trees, what happens when you install the new platforms? Do you run everything through the platform, or do you leave those subsea trees in place, and produce off of those?

We could have done it either way. But what we're going to do is we're going to utilize the flow lines that are coming from the 5H and 6H well, as our connection between the platform and the FPSO, so that we don't have to run a bunch of new risers and things over to the FPSO.

So, we're going to re-route the 5 and 6H well to the new platform, and then use their dual flow lines as the conduit to get the oil back to the FPSO. And that's the work that I was referring to that we're doing right now, while the shutdown is going on, is we're disconnecting the 5H, 6H pull lines. We're laying a loop that we can then come back later and connect up to the platform, and then everything will be connected back to the FPSO, the subsea wells and the new wells that we drill with dry trees on the platform.

Okay. Thank you.

And Greg, could you address -- in the Q4 revenue barrels, you had 531,000 Etame barrels approximate, but that represents only 24.587% of the total lifted from Q4, and that doesn't line up with your Etame working interest percent. Is there --

It's a function of royalty, Neil. Our 28% interest -- we first drop off 13% for royalty. If you take our 28% working interest times 0.87, it comes to the 24% number that you mentioned.

Okay. That explains it.

Yes, we don't report royalty as revenue. In Canada, they do, for example; but we don't. It's not US GAAP.

That covers all of my questions. Thank you very much.

We do have a follow up from Eric Anderson. Please go ahead.

I wonder if I could just go back a little bit to -- in your concession in Equatorial New Guinea. I believe in a prior presentation, possibly out at EnerCom, Steve, you talked about that there was a proved discovery there that has not been developed, and just wonder if you could put that in perspective for us, and then also possibly where that is in relation to wells that you're planning on drilling in the area?

Yes, I may get some help from (inaudible) known as the Venus field. It was a discovery made by Devon in 2005, and it is -- we estimate the gross recoverable to be around 17 million barrels.

17 to 20, yes. It's a nice little discovery, and actually Devon filed a development plan to develop it, but the government rejected it because they wanted them to drill some of the other channels to make sure that they sized the FPSO correctly. They didn't want them to go in there with their small FPSO and then find the mother lode somewhere else, and wish they had different facilities, et cetera.

So, we've talked to the government about whether we could develop it standalone, and I think everybody just feels like we ought to drill these two other big channel sands and see what's in them before we decide what facilities we need out there.

And how far apart are they from one another?

Oh, they're all within 15 miles of each other, maybe less. They're kind of like Etame, Avouma, and Ebouri. They could all be easily connected together. So, then it's the question of where do you want to have your mother facility? Do you really want it at Venus, or is one of the other ones a lot bigger, and it would make more sense to have your FPSO nearer to that.

But you hope to have at least one or both wells down this year?

We're trying as hard as we can.

Okay. Thank you very much.

And at this point, no additional questions in queue.

Okay. John, that's great. I think we'll sign off for now. And we'll come back in May when we talk about our first-quarter 2014 results.

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