Ladies and gentlemen, good morning, thank you for standing by, and welcome to VAALCO Energy Third Quarter 2015 Earnings Report. [Operator Instructions] As a reminder, this conference is being recorded. I'd now like to turn the conference over to our host, Investor Relation Coordinator, Mr. Al Petrie. Please go ahead. Al Petrie Thanks, Tom.
And on behalf of the management team, I welcome all of you to today's conference call to review VAALCO's third quarter 2015 operating and financial performance. After I cover the forward-looking statements narrative, Steve Guidry, VAALCO's Chairman and CEO, will review key highlights of the third quarter.
Following Steve's comment, Greg Hullinger will provide a more in-depth financial review and update to our 2015 guidance. Cary Bounds, our COO will then review operational results in more detail and our plans for the balance of 2015. Steve will then return for some closing comments before we take your questions.
On November 6th, the company issues a statement in response to Group 42 and Bradley Radoff filing a consent solicitation material. VAALCO's responsive matters are discussed in the filing, and the Board will be providing a recommendation to our shareholders in due course.
We appreciate you limiting any questions in today's call to those regarding third quarter financial and operational matter, and not regarding the consent solicitation. Please note that our earnings call today does not constitute the solicitation of consent or proxy.
During our question session, we ask you to limit your questions to one and the follow-up. With that, let me proceed with our forward-looking statement guidance. During the course of this conference call, the company will be making forward-looking statements.
We caution you that any statement that is not a statement of historical fact is a forward-looking statement.
Forward-looking statements are those concerning VAALCO's plans, expectations, future drilling and completion activities, expected capital expenditures, prospect evaluations, negotiations with governments and third parties, reserve growth and other operations.
Statements made during this conference call that address activity, events or developments that VAALCO expects, believe or anticipate, will or may occur in the future are forward-looking statements.
These statements are based on assumptions made by VAALCO based on its experience, perception of historical trends, current conditions, expected future developments and other factors it believes are appropriate in the circumstances.
Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond VAALCO's control. Investors are cautioned that forward-looking statements are not guarantees of future performance and those actual results or developments may differ materially from those projected in the forward-looking statements.
VAALCO disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Accordingly, you should not place undue reliance on forward-looking statements.
These and other risks are described in yesterday's press release titled Forward Looking Statements and in the reports we filed with the Securities and Exchange Commission, notably the 2014 Form 10-K filed with the Commission on March 16,2015 and Form 10-Q filed with the commission on May 7, and August 06, 2015.
Please note that this conference call is being recorded. Having provided you with our forward-looking statement guidance, I will turn the call over to Steve Guidry.
Steve?.
Thank you, Al. Good morning everyone, and welcome to our third quarter 2015 earnings conference call. Before I get in to the quarterly results, let me begin by welcoming Don McCormack to our executive team as our CFO.
Don has extensive financial background in the energy industry, having served in key financial leadership positions with other publicly traded EMP companies. He has significant international and domestic experience in accounting, treasury, M&A, and corporate finance.
His overall financial and public markets' experience will serve VAALCO well in the future. Let me also thank Greg Hullinger for his financial leadership here at VAALCO over the past seven years.
Greg was actively involved in all facets of our business and was a trusted financial advisor to senior management and the Board, and was our primary investor relations contact. We wish him the best in his upcoming retirement.
On the call this morning, we will reference an updated supplemental information slide deck located on our Web site, which builds on the improvements that we made last quarter on enhancing the information we provide to our shareholders.
As you already know, 2015 has been a volatile year for the energy industry with continued weakness and uncertainty in commodity prices. Because of this volatility, our strategy is directed toward lowing cost, investing in projects that yield good economic return in the current price environment, while remaining focused on shareholder value.
Our development drilling success in our multi-well offshore Gabon program resulted in continued production growth in the third quarter. Contributing to that increase in volumes was strong production from our Southeast Etame 2-H well, completed in July, and an incremental production from the North Tchibala 1-H well, completed in mid September.
Combined with the two successful wells drilled earlier this year on the Etame platform, our 2015 drilling program has added about 1100 net barrels of oil per day to our year-to-date volumes.
This success allowed us to average production of about 4800 barrels of oil equivalent per day for the third quarter, slightly above the upper end of our guidance range. You can see the growth in production that this program has contributed to VAALCO on Slide 4 of the supplemental information.
Notice that the impact to the fourth quarter volumes from our development program will be about net 1800 barrels of oil per day. This accounts for over 33% of our fourth quarter 2015 volumes.
Based on these successes and the anticipated volumes from our North Tchibala 2-H well currently drilling and some limited late year production benefit from the planned Avouma platform workovers, we expect our fourth quarter production to be in the range of 4600 to 5000 barrels of oil equivalent per day.
Taking all this into account, we are raising the range of our full year 2015 production guidance to be between 4400 and 4700 barrels of oil equivalent per day. Cary will discuss the results of our drilling program and plans for the rest of the year in more detail shortly.
Because of the recede within the North Tchibala 2-H well and the workovers, along with increased costs associated with the partial well re-drills, we have revised our full year 2015 capital program to $83 million to $86 million.
In the third quarter of 2015 we were not able to fully benefit financially from the higher production, largely due to the 26% decline in oil price realizations, and more listings compared to the second quarter of 2015.
If you look at Slide 5 of the supplemental information, you will see that listings fluctuate from quarter-to-quarter due to a variety of factors, including the timing and the volume of each offloading.
Our net average monthly liftings totaled 390,000 barrels in 2013, then declined to 340,000 barrels in 2014, and are averaging about 420,000 barrels for the first nine months of 2015. We're anticipating a further increase in fourth quarter listings, evidenced by the strong October listing that we recently disclosed in our Web site.
Hopefully, prices will be higher as well, but we can't control prices, and we must continue to focus on what we can control, which are the costs associated with this production. VAALCO began reducing costs even before decline in oil prices, as we began taking steps in 2014 to reduce executive cash compensation.
In 2015, we've reorganized and reduced our corporate staff, and have further reduced costs at the field level. The benefit from these actions result in a downward trend of our production expenses in 2015, while corporate G&A cost reductions will be more evident in 2016.
Regarding production expenses, we're making more efficient use of helicopters and marine vessels. We've also reduced our manpower costs through a 20% across-the-board reduction in day rate for all rotating expatriates, and cut other related benefits as well as we've taken actions to lower travel costs.
We're also achieving a 10% to 15% production cost reduction since the beginning of the year. We have additional plans to further reduce costs in the early 2016, as our development projects beings to wind down. Additional detail on our production expense reductions can be seen on Slide 7 of the supplemental information.
I'd like to point out that we have reduced production expenses on a per BOE basis over the past year, from $27.43 per BOE in Q4 of 2014 to $19.36 per BOE in Q3 of 2015. We also expect Q4 of 2015 to be even lower, and that's shown in the range to be between $16.50 and $18.50 per barrel of oil equivalent.
On the G&A front, let me remind you that in early 2014 we increased our staffing levels when we undertook the two-platform design, fabrication, and installation projects, and the subsequent six well drilling program, and have already made changes to meaningfully reduce our future G&A costs.
We are cutting our aggregate future executive and management cash compensation 30% compared to 2013. We've also reduced our corporate staff in Houston by approximately 15%, as well as we've reduced our contract services, and other third-party costs.
We will continue to make the difficult decisions to ensure that we're delivering on our 2015 cost reduction initiatives. Moving into 2016, we'll seek out additional opportunities where we can reduce expenses and ensure we are competitive on a position to weather a lower-for-longer oil price environment.
We generated positive adjusted EBITDAX of $8.2 million in the third quarter, despite the 26% decline in oil prices, and the 13% decline in liftings between the second and third quarters.
On a BOE basis, as shown in Slide 9, cash reduction expenses remain low at $19.36 per BOE, and cash G&A with $6.92 per BOE after severance expenses, resulting in a positive adjusted EBITDAX for BOE of $20.19 despite the lower prices and listings. Now let me turn the call over to Greg for a more detailed review of our third quarter financials..
Thank you, Steve. I will be reviewing key financial information pertaining to the third quarter of 2015 that we reported yesterday in our earnings press release and the SEC Form 10-Q. I will also be providing guidance information pertaining to the remainder of the year.
We reported an adjusted net loss of $6.5 million or $0.11 per diluted share for the third quarter of 2015. Adjusted EBITDAX was $8.2 million in the third quarter of 2015. The third quarter adjusted net loss number is before $18 million non-cash impairment charge related to the Etame Marin Block, offshore Gabon.
Also included -- pardon me, also excluded was $9.2 million non-cash charge exploration expense for a well that we drilled in 2012, onshore Gabon in the Mutamba Iroru Block. I'll be talking more about these items in a couple of minutes. For comparison, adjusted net income for the second quarter of 2015 was $0.6 million or $0.01 per diluted share.
Including the impairment and well write off, GAAP net loss for the third quarter was $33.7 million or $0.58 per share. This compares to a net loss of $5.2 million or $0.09 per diluted share in the second quarter of 2015. The impact of lower oil prices continues to be clearly seen in our quarterly revenue number.
Revenues up $17.5 million reported for the third quarter of 2015 were lower than the 27.1 million of revenues for the second quarter of 2015. The average oil price we received in the third quarter of 2015 was $43.97 per barrel, compared to $59.16 per barrel in the second quarter of this year; a 26% decrease.
Going back a year ago to the third quarter 2014, the oil price averaged $94.67 per barrel, a decrease of 54% when compared to the third quarter of 2015. Barrels lifted during the third quarter of this year in Gabon of approximately 396,000 barrels were lower than the 455,000 barrels lifted in the second quarter of 2015.
The higher Q2 lifting amount resulted from a large opening inventory balance that was lifted during that period. Revenue is a function of both price and the amount of barrels sold via the crude lifting that occur in Gabon on approximately a monthly basis.
Top of net production from Gabon in the third quarter of 2015 was 431,000 net BOE or 4,700 net BOE day, compared to approximately 404,000 net BOE or 4,400 net BOE per day produced during the second quarter of this year; a 7% increase.
Production in the third quarter of 2015 was approximately 21% higher than the third quarter of last year at 358,000 net BOE or 3,900 net BOE per day. Production increases are attributable to new producing development wells that were drilled post third quarter 2014, including two wells brought online in the third quarter of this year.
Cary will be providing more information on this topic shortly. VAALCO'S working interest in the inventory of bold FPSO vessel at September 30, 2015 was approximately 55,000 barrels versus approximately 27,000 barrels at June 30, 2015. Next, let me move to other key financial components for the third quarter of this quarter.
Operating loss was $32.1 million in the third quarter of 2015, compared to an operating loss of $1.0 million in the second quarter of this year.
The operating loss in the third quarter was significantly impacted by the impairment charge of $18 million to adjust to fair value certain fields in the Etame Marin Block and the $9.2 million for the [indiscernible] Gabon well write-off, as it no longer met the criteria for capital treatment as suspended exploration low cost.
In connection with this assessment of impairment for the three months ended September 30, 2015, the company identified an immaterial error; just a material error was present in the calculation on the impairment for the December 31, 2014, March 31, 2015 and June 30, 2015 periods.
As a result of this error, the impairment charge of $98.3 million recorded for the year ended December 31, 2014 was understated by $7.0 million or 7.2%.
The impact of the error resulted in an overstatement of an impairment charge of $3.1 million for the three months ended March 31, 2015, and an understatement of the charge of $0.5 million for the three months ended June 30, 2015.
In accordance with Staff Accounting Bulletin or SAB, number 99 titled Materiality, and SAB number 108 titled Considering the effect of prior year misstatements when quantifying these statements in current year financial statements, we evaluated these errors, including both qualitative and quantitative considerations, and concluded that the errors did not individually or in the aggregate result in a material statement of our previously issued consolidated financial statements.
For more information, please refer to our 10-Q filed yesterday. Additionally, we incurred a $13.5 million impairment charge based on our third quarter assessment of impairments for the North Tchibala field.
Lower projected oil prices and higher well costs were considered in the fair value evaluation of that field were the factors that brought about the current period impairment charge. Production expenses for the 2015 third quarter were $7.9 million or $19.36 per BOE, compared to $8.9 million or $19.08 per BOE for the second quarter of 2015.
The decrease in the expense amount is attributable to cost reductions and contract services, materials, and operational efficiency, much of which Steve talked about just a minute ago. We're slightly increasing our production expense guidance on an absolute basis to $33 million to $34 million for full year 2015.
While we're slightly raising the absolute production expenses, our per unit costs are expected to decline. Cary will talk about this in more detail shortly.
As we've previously discussed, we anticipate we'll have up to three workovers performed in the Avouma and South Tchibala field in the fourth quarter through electric submersible pump at an approximate combining net cost of VAALCO of between $6 million and $9 million.
Our plan is to begin the workover as following the completion of the North Tchibala 2-H development well. Exploration expense for the third quarter of 2015 was $9.0 million, compared to $1.1 million recorded in the second quarter of 2015.
Exploration expense during the third quarter of this year includes a $9.2 million non-cash charge for suspended exploratory well costs related to the Mutamba Iroru, onshore Gabon block. We drilled a successful exploration well in [indiscernible] number two in 2012 and have recorded it as an asset on our book as suspended well cost since that time.
We conduct quarterly evaluations to determine whether sufficient progress has been made towards development, as well as the economic and operational viability of the project.
We determine the investment in the well did not continue to meet the criteria for suspended well cost in the current quarter, primarily based on lower projected oil price data and updated development cost scenarios. Accordingly, the costs were recorded as exploration expense in the third quarter of 2015.
Exploration expense for the fourth quarter 2015 is expected to be minimal. DD&A for the third quarter of 2015 was $8.3 million, compared to $9.3 million in the second quarter of 2015. The third quarter DD&A rate was $20.34 per barrel.
Guidance for the fourth quarter is a range of $20 to $22 per barrel, and we expect to be in the range of $19 to $22 per barrels for full year 2015. General and administrative expenses for the third quarter of 2015 totaled $3.8 million, comparable to the $2.8 million recorded last quarter; 0.3 million of new increase is due to severance cost.
Guidance for net G&A expense is expected to be in a range of $15 million to $16 million during 2015. Other cost and expenses up $2.8 million represents a further bad debt allowance taken on the value-added taxes receivable we have from the government of Gabon.
We recorded bad debt expense in the third quarter of 2014 of $1.8 million for the same reasons. These bad debt allowances against the accounts receivable balance were taken to reflect slow repayment by the Republic of Gabon to reimburse the company for its VAT payments.
Across the industry in Gabon, the Republic has not been repaying these amounts as timely as they had in the past. Repayments by the governments have a history of being non-timely, but in periods, repayments are following further behind. No reimbursements were received in the third quarter of 2015.
We recorded the bad debt expense to reflect the further slowdown and uncertainty in receiving payments stating back as far August of 2012. We'll be able to recognize the allowances taken as income if we ultimately receive these monies that are owed to us.
The full amount owing the company at September 30, 2015 -- this is again before the allowances, was $8.9 million. In addition, the unreserved VAT receivable wells have been reclassified from the current asset section to the non-current asset section on the balance sheet beginning this reporting period.
Income tax expenses for the third quarter of 2015 were $2.7 million, compared to $4.3 million in the second quarter of this year. The decrease in income taxes reflects the impact of the lower sales price received for oil sales during Q3, 2015.
Cash and cash equivalents, including restricted cash totaled $57.6 million at the end of the third quarter of 2015. This compares to $78.1 million at the end of the second quarter of 2015, and $91.5 million at the end of 2014. We also have $50 million of un-drawn capacity on our $65 million IFC credit facility.
Capital expenditures spent totaled $72.2 million through the first three quarters of 2015. As Steve discussed, our guidance regarding capital expenditures in 2015 is expected to be in a range of $83 to $86 million. And with that, I will turn it over now to Cary, who will provide you with an operational update..
All right. Thank you, Greg, and I'm excited to provide more details on the positive operational developments that we had this past quarter, and then take a look ahead for the balance of 2015. Let me start with a few comments on production performance.
The wells drilled and completed so far in 2015 have made a substantial contribution to our production rates. As Steve mentioned, third quarter production exceeded the high end of our guidance range.
The primary driver behind exceeding third quarter production expectations was better than expected performance from the new wells that came online in the quarter, which were the Southeast Etame 2-H and the North Tchibala 1-H.
However, the production uplift from our new wells was partially offset by the natural decline we see in the underlying base production from wells drilled prior to 2015.
In addition, strong production from the new wells also helped us overcome loss production as a result of shutting in the South Tchibala 2-H well due to an electric submersible pump failure. Now, I'll turn to our drilling campaign, and talk about our development well results.
All of our third quarter drilling was conducted from the SEENT platform, which was installed in late 2014. The SEENT platform came online trouble-free in July with first oil from the Southeast Etame 2-H well.
As I mentioned earlier, production performance from the Southeast Etame 2-H well exceeded expectations, and the well continues to produce its strong rate.
Upon completion of the Southeast Etame 2-H, we successfully drilled and completed the North Tchibala 1-H, which is a development well in the Dentale D-9 formation, which was discovered in 1977 prior to VAALCO having an interest in the block. The Dentale formation already produces from onshore Gabon fields that have never produced offshore.
We're very proud that the North Tchibala 1-H established the first Dentale production to the industry in the offshore waters of Gabon.
As Steve noted earlier, the North Tchibala 1-H well was drilled to approximately 11,200 feet measured depth, and came on production on September 15 at about 3000 barrels of oil per day with no H-2s and no water production.
The 1-H well exceeded our expectations and produced at a sustained rate of 3000 barrels of oil per day for six weeks with minimal pressure depletion. We were continuously monitoring the well performance, and we recently observed a decline in bottom hole pressure accompanied by an increase in the gas production rates.
In response to the drop in pressure, we have chucked the well back to stabilize bottom hole pressure and greater decrease by a 1000 to 1500 barrels of oil per day. Even with the reduction in rate, production from the well was still slightly higher than our initial expectations.
I want to emphasize that it is too early to determine the extent of the impact we recently observed pressure depletion may have on the wells line trunk performance and we will continue to monitor and optimize the well.
Turning things the North Tchibala 2-H where we are currently drilling, this well is targeting the deeper Dentale D-18/19 formation at about 16,000 feet measured depth, and we believe the North Tchibala 2-H will be the longest well ever drilled in Gabon.
We ran and submitted intermediate casing at approximately 14,600 feet measured depth without encountering any problems while drilling. We're currently in the process of re-drilling the last 1800 feet of lateral section in the well bore after encountering hole stability issues with the open hole portion of the well.
The initial lateral encountered good quality reservoir and we believe they will have the same or possibly better quality reservoir in the replacement lateral. We still expect to have the results from the well by late November.
So far the reservoir results from both the North Tchibala 1-H and North Tchibala 2-H are encouraging, and we're looking for other areas on the Etame Marin Block to develop the Dentale.
If you take a look at Slide number 11 in the supplemental information, you will see several other areas on the block where we think there's been health potential, and we are looking at these areas closely.
However, it will take additional drilling, along with long-term monitoring of the first two wells before we have a clear understanding of what that ultimate potential might be. Future drilling may include another Gamba development well on the Etame platform, and this well could also access the Dentale formation in the main Etame south block.
Now, I will spend a few minutes on the schedule for the remainder of the year. Given favorable fee stake conditions, our contract jackup rig, the Transocean Constellation II will move to the Avouma platform after completing the North Tchibala 2H well.
On the Avouma platform, the rig will perform workovers to replace electrical submersible pumps, or ESPs, in three existing wells, two of which are currently offline. The production uplift from the two offline wells is expected to generate returns greater than a 100% using current strip pricing.
The third workover is for preventive maintenance to minimize the risk of an ESP failure in the future. The production impact from the workovers will be minimal for fourth quarter 2015 volumes, but we do expect to see a robust production boost by early 2016.
Moving from drilling to operations, the 2015 planned shutdown for annual maintenance on the Etame block has been rescheduled to January 2016. The planned shutdown is expected to last approximately six days, during which period all producing wells will be shut in.
Moving on to the crude sweetening project, our engineering team continues to focus on evaluating the most cost effective crude sweetening option for the removal of H2S from the affected wells that are burying in Etame. The outcome of the team's evaluation is expected to be reviewed by the Etame partners in the fourth quarter of 2015.
Moving to onshore Gabon and our Mutamba project, where since mid-2014, we have been working to finalize a revised PSC with the government of Gabon to allow for development of the discovery, and to maintain exploration rights on the block. We received a letter last month from the Gabon government expressing their view that the initial PSC has expired.
The letter also encouraged us to quickly negotiate to enter into a new PSC, thereby preserving our rights to the 2012 discovery, and the current cost account. VAALCO and our joint venture partner are in agreement that the initial PSC has not expired.
Further meetings were held, in October of this year, with the government and our joint venture partner to discuss possible new PSC terms that take into account the recent substantial decrease in oil price.
We plan to continue meeting with the joint venture partner and the government in an effort to negotiate, and to enter into a new PSC that will give us the opportunity to develop discovered resources on the block.
Turning our attention to Angola, the company recently opened a data room in London to seek to farm out a portion of our working interest in Block 5 offshore Angola.
We previously mentioned that our interpretation of the reprocessed 3D seismic data on the block has identified four top prospects with an estimated total gross un-risked mean recoverable resource potential of over 800 million barrels of oil.
A number of large independent exploration and production companies, as well as major oil companies have expressed interest, and signed confidentiality agreements, and we'll be reviewing the data over the coming months. We are excited about the potential in Angola, but we'd like to mitigate some of the exploration risk through this drawn out process.
The current concession extends through November 2017 with multiple additional exploratory drilling in Angola expected before early 2017. As Steve has mentioned in the past, our remaining three commitment wells in Angola each have termination clause of $5 million net to VAALCO.
While there are no current plans to drill additional wells on Block 5 until early 2017, any future actions in Angola will depend on our cash position, the forecast of oil price at the time of the rig commitment, the revised estimated cost to drill the wells, the success of our [indiscernible] efforts, as well as the size and quality of the targeted prospects.
In Equatorial Guinea, we continue to work with the Ministry of Mines, Industry, and Energy, as well as GEPetrol, the current block operator, on a revised and joint operating agreement, which we expect will name VAALCO as operator.
We've had good dialogue in recent months with our partners, and we are working on timing and budgeting for the project, including the approval of a development and production plan.
Development project economics are being reevaluated, considering continued low oil prices, and the expected decrease in development costs associated with the fall in oil prices. Finally, I would like to wrap up the operations update by talking about the operational cost reductions that we have put in place.
This past year, we implemented sustainable cost reductions through work efficiencies, reducing contract services, reducing material costs, and rightsizing our operations organization. None of these cost reductions have impacted our focus on asset integrity, safety, and environmental performance.
As you can see on Slide 6, the cost reductions are coming from a number of areas. And the most notable reductions are associated with changing the way we do our business in terms of logistics, manpower, and chemicals.
As you can see on Slide 7 of the supplemental information, we have been successful in our efforts to reduce costs on a unit basis, from $27.43 per BOE in the fourth quarter of 2014, to a forecast of approximately $18 per BOE in the fourth of 2015.
We are capturing these savings and efficiencies, and believe that we have approximately 400 -- I'm sorry, approximately $4 million net in cost reductions heading into 2016.
To close out, I want to emphasize that we are focused on conducting our operations in a cost-effective manner, without compromising safety, the environment, or the integrity of our assets.
The growing production profile in Etame has really helped improve our financial performance as we have brought high-margin barrels into our existing operating infrastructure.
We are generating positive results as we deliver on the strategy that Steve laid out earlier, to reduce costs, economically develop production, and to add shareholder value as we continue to look for more efficient ways to run our operations. With that, let me now turn the call back over to Steve..
Thanks, Cary. As we look past the North Tchibala 2H development well, currently drilling, and the upcoming 3-well Avouma South Tchibala workover program, we will consider any further drilling beyond that point in 2016 on a well-by-well basis.
As previously discussed, in early 2014, VAALCO and its partners contracted with Transocean for the use of the Constellation II jackup rig through July 5, 2016. We have a portfolio of additional Etame development wells in both the Gamba and the Dentale formations as options for continuing the drilling program beyond this year's commitment.
Additionally, to provide us with maximum flexibility next year, we've hired a broker to actively market the rig to other operators.
Should VAALCO and its partners elect to not fully utilize the rig for the entire contract duration, and if the subleased options are not available, a day rate charge for the unused portion of the contract would be incurred. We are currently discussing our 2016 budget with our partners.
And as you can see on Slide 13 of the supplemental information packet, we have several scenarios that we are currently evaluating. The first possible scenario is to release the rig after the workovers, which will cost us approximately $9 million in unutilized day rate charges net to VAALCO.
But you should keep in mind that we benefited from lower day rates than we otherwise would've had with a shorter term rig contract. In this scenario, our total net capital expenditure for 2016 would be estimated to be in the $14 million to $16 million range. That's inclusive of the day rate charge payment to Transocean.
The second scenario is to drill one additional development well, likely an Etame platform well with the Dentale pilot test that Cary mentioned. This would result in approximately $20 million to $26 million in total net capital, and reduce the unutilized day rate charges to approximately $6 million net to VAALCO.
The third scenario involves the drilling of two additional wells, with approximately $4 million of unutilized day rate charges, and a total net CapEx spend of approximately $28 million to $33 million. As you can see, all three of these possible scenarios are significantly lower than our 2015 CapEx spend, of $83 million to $86 million.
We're currently forecasting that cash flow from operations will exceed the cash required for aiming at these possible capital investment scenarios, assuming $55 per barrel dated Brent pricing.
We're working closely with our partners to identify the appropriate course of action for all parties involved that will allow us to maximize the value of every dollar spent. And obviously, oil prices will have a significant impact on our future drilling plans. With that said, we continue to have a very strong balance sheet.
And in the current price environment, we want to protect our liquidity, while remaining opportunistic in our investment decisions, allowing us to follow -- to stay focused on shareholder value.
In summary, I'd like to reemphasize the fact that our strategy is directed toward lowering costs, investing in projects that yield good economic returns in the current pricing environment. And remaining focused on shareholder value. We've done a good job of achieving a strong production result from our drilling program.
Unit operating costs have been reduced. And we're maximizing the margins that we make on every barrel that we sell. We're in a strong position, financially, to be opportunistic in the current macro pricing environment.
We will strive to improve our operating performance even further, and continue to deliver free cash flow, with the consistent goal of enhancing shareholder value. Thank you. And with that, Al, we are ready to take questions..
Okay. Tom, we're ready to open up the queue for questions..
Thank you. [Operator Instructions] Our first question today comes from the line of Leo Marina with RBC Capital. Please go ahead..
Hi guys, appreciate the update.
I was hoping to get a little bit more color on how that first well in Southeast Etame is currently holding up in terms of what it's producing, and then with the overall current production in VAALCO right now?.
Thanks, Leo. The well is doing very well. The Southeast Etame well continues to perform well. In fact, as we said in our prepared remarks, we're very happy with the last four wells that we drilled, the four wells we drilled in 2015. The Southeast Etame, just as a reminder, was drilled to an area of the field that's a Gamba producer.
So it's continuing to exhibit the kind of performance that we've come to expect from the Gamba. And for more details, let me just ask Cary to give us an update on that well in particular. I can tell you that our current production is, right now, circa 20,000 barrels a day gross..
That's right, Steve. Our gross production is around 20,000 barrels a day gross, and a big contributor is the Southeast Etame 2-H well. And Leo, it is -- we have not really seen any material decline in the well's rate or pressures. It's a very strong well..
Okay. So I guess it came on at 3000 barrels a day.
So it's still at 3000 barrels a day, is what you're saying?.
Yes, very close to 3000 barrels a day..
Okay. In terms of your oil price realizations in the third quarter, I guess they are roughly $6 below Brent. Want to get a sense of where you think those are going to be going forward. I know that you guys were able to get a new contract [indiscernible] production..
Yes, Leo. Let me take that one. We have experienced a widening of the differentials in West Africa. We -- last time oil prices dipped to this level, we saw a widening of the differentials. That improved a bit when we saw the bump this summer, when prices went back above $60.
But we're continuing -- now that prices are back down again, the differential is beginning to widen. So I think it's a sign that West Africa crude oil is right now, in this environment, have to travel further, and are just less sought after. But we are using an estimate of about $5-a-barrel differential going forward..
Okay, that's helpful. And I guess in terms of the Dentale reservoir, obviously a good first well resolve there.
Trying to get a sense, do you have any reserves booked in the Dentale in terms of either 1P or 2P at year end '14?.
Yes, we do. I'll say this, that the majority of those reserved [ph] are booked and probable, not in proven developed, but I think -- let me ask Cary to give you confirmation on that..
If I recall correctly, Leo, it's a very nominal amount that's booked and proven, maybe 0.2 million barrels, and then I think 0.3 million barrels are in probable. And that's for, like I said, the Dentale development offset..
And those numbers are net to that..
Okay. Thanks, guys..
Our next question comes from Matt [indiscernible] with Titan Capital. Please go ahead..
Great, thank you. I was curious.
The guidance for Q4, does it include any costs for the activist investor, the situation that you're facing here today?.
We were looking to limit our comments to Q3, but you're right. Q4, we are anticipating additional costs. Those costs are not included in any guidance that we've given. They'd be extraneous to that current guidance, and so, you should look for us to report on that. It's kind of a separate item in Q4..
Okay, okay. Also wanted to ask about Angola, the [indiscernible] timeline, as you sit here today, what's your expectation with current pricing? I know you have the data room open. Just discuss your expectations around Angola today..
Right. Well, we're very excited about the uptake that we've seen in companies interested in our data room in London. The number continues to climb, but I want to say we had 12 companies currently have indicated an interest. Four of those have been through the data room. The rest are in queue to go through the data room.
So, lot of interest in the project.
What we've done is for 2016 we have included monies in our budget for long lead materials to put us in a position to be able to executive on drilling program in 2017, and it's too early right now for us to say just exactly how the form out [ph] will turn out, but we're hopeful that we will be successful in giving a carry on these wells, and will be able to move forward according to the plan..
Great. Thank you..
There are no other questions queuing up at this time..
Okay. Well, let me thank everyone for your attention, and your participation in this morning's call. We look forward to visiting with you in the end of our -- at the end of the 2015 where we can give you a full year view of how our performance backed up..
Tom, it looks like we have picked up one more question that's come up, from Leo Marina..
Okay. We will go to the Leo Marina's line, RBC. Please go ahead..
Hey, guys, just a quick follow-up question here. Obviously your CapEx trending upwards in 2015, kind of chunky number here on the third quarter, just over $30 million.
Trying to get a sense, you guys referenced some higher drilling costs, are you guys actually seeing kind of higher per well cost, or was this been more resulted some mechanical issues we had to re-drill some wells this year in terms of your well costs?.
A good question, Leo. Let me speaks [ph] up, then I'll ask Cary to give you some additional details, but in drilling [indiscernible] last time, we're drilling wells that are really cutting-edge for Gabon.
These wells we're drilling really are the first wells that have ever been drilled in -- deviated wells that have been drilled through the formations that we're drilling, primarily the Dentale, which is a stack same shield sequence, and we've had some hole stability and mechanical issues with the wells we drilled off at present [ph].
I'm happy to say that our team has reassessed our approach to these wells. We've had an outside party come in and look at all of our drilling plan, drilling parameters.
We've made adjustments to the drilling plans, and with time we've been able to really get our hands around the drilling cost, and we had fewer and fewer drilling problems on the SEENT platform as we've gone from the -- first off the Etama well. We had fewer on the North Tchibala 1-H well and we had minimal problems now on the North Tchibala 2-H well.
So, they have done a great job of -- Cary, take a little bit of….
Yes. That's a good summary, Steve, and I'll just add that like Steve mentioned, we have incorporated lessons learned from our early wells in the drilling campaign, and we found that we needed the change, say, the well design to account for H2s. So we've added metallurgy to the new wells that is compatible to H2s.
Based on some of the hole stability issues we saw early in the campaign, we switched from drilling with water base mud to oil base mud, and that increased the cost a little bit.
And then unfortunately early in the campaign we did leave bottom hole assemblies behind in two wells, and that cost us some money, but like Steve said, we're seeing some dramatic improvements, and we don't envision that will happen again..
Okay.
So, what do you see as a kind of run rate number to drill one of these wells in the Etame, where we're in concession with the jackup going forward here, in terms of gross and the net?.
It depends if you're drilling down below Dentale, but our Gamba wells, I think we're currently estimating to be in the range of $32 million gross. So, just over $10 million, I'm not sure. And the Dentale wells, I think we're estimating to be gross of in the $37 million to $39 million..
Okay. Thank you, guys..
Thank you..
We did have one other question, would you like to take that?.
Yes, that would be fine..
Okay. We'll go to line of John Kornitzer with Kornitzer Capital Management. Please go ahead..
Can you hear me okay?.
Yes, we can, John. Good morning..
Good morning.
On these wells, what do you need for gross production to make them profitable at $45 a barrel or $50?.
Yes. So, we don't have that number in front of us right now, but we're estimating that these wells were, I'd tell you, add $55 oil. I think we're estimating these wells to be rate of returns in the 30% to 40% range..
Okay..
To your point, John, we think that a 1500 barrel a day gross initial rate is what's necessary for us to earn an acceptable rate of return on a Gamba well..
Okay. I know you were also been coming in at over 1500 barrels a day..
We have been, yes..
Okay. I think, I mean you've done an excellent job with this company.
You said you had bad luck this past year in drilling some of these wells, and the cost were extremely high, but when I think about the number of oil companies, you know, bankruptcy, they have lost a tremendous amount of their value, because oil dropped down to 40 some dollars a barrel. You guys are in excellent shape financially.
We're not talking about you going bankrupt. I'm not talking about restructuring any debt. We're not talking about anything that's life threatening to the company, except the price of oils down and that's just going to be a matter of patience where to go back up.
What I don't understand is -- I'm extremely happy with the company, okay, and I think you guys have done an excellent job, okay. Nobody can predict when the well when you drill it.
Your cost overruns because what rigs were the past couple of years, because oil was over a 100 -- was very acceptable, drilling a rig was very tough, you had timelines you had to drill.
Monday morning quarterbacking is a great deal of that in football and basketball and baseball and everything else, but Monday morning quarterbacking is easy, but being there making the tough decisions is tough, and I want to congratulate you on the excellent jobs you guys have done over the years, especially with the new team you're doing a great job, the Board is pinned with you all the way, and it's very hard you changed things within the company within 10 days, and people not up to speed can make a big blunder going forward.
So, I congratulate you, and keep up the good work..
John, thanks for those comments. We've done everything we can to make the best of a bad situation, and I think it was fortunate for our company that as oil prices well we did have the cash balance necessary to continue to fund the development.
That was a luxury that most other EMP companies did not have, and I think it's put us in a very favorable position now with production near peak level. The way we see, we will be able to weather the storm going forward. Thank you for the comment..
You're welcome. You well deserve it..
There are no other questions queued up at this time..
Again, thanks to everyone for your time this morning, and thanks for your interest and your questions and your investments. We appreciate it. Thank you very much..
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