Victoria Oil and Gas has now released their final results for the year ended 2016.
Revenues increased by $11.4M but production royalties grew by $1.4M and depreciation and amortisation was up $11.9M. Other cost of sales fell by $1M but the gross profit was $983K lower. Wages and Salaries were up $1.2M, professional fees increased by $968K and other admin expenses grew by $2.4. There was also a $405K increase in forex losses but a $22.7M impairment of oil and gas assets gave an operating loss $29.4M worse than last time. There was no reversal of provisions, which brought in $1.2M last time and the unwinding of provision discounts increased by $851K before a $320K decline in tax charges meant that the loss from the year was $31.1M, a detrimental movement of $31.3M year on year.
When compared to the end point of last year, total assets declined by $17.1M, driven by a $33.6M fall in the value of oil and gas assets, a $5.3M decrease in RSM receivables and a $1.4M decline in deferred tax assets, partially offset by a $16.7M growth in exploration assets, a $3M increase in cash, a $1.8M growth in the value of plant and equipment and a $1.8M increase in assets under construction. Total liabilities increased during the period due to a $3.2M growth in trade payables due to increased expenditure on the drilling programme, a $7.3M increase in loans and a $1.4M growth in legal provisions. The end result was a net tangible asset level of $77.3M, a decline of $47.4M year on year.
Before movements in working capital, cash profits increased by $3.4M to $12.7M. There was a large cash inflow form working capital due to a decrease in receivables and an increase in payables so that after tax payments increased by $283K the net cash from operations was $22.2M, a growth of $20.6M year on year. The group spent $16.3M on exploration and evaluation along with $10.7M on property, plant and equipment so that after a $1.5M receipt of dividends from an associate there was a cash outflow of $3.2M before financing. The group took out a net $7.3M of new borrowings to give a cash flow of $3.9M and a cash level of $16.3M at the year-end.
There was a 24% increase in gas sales to 3,566mmscf gross driven by gas sales to two Douala power stations and the expanding thermal gas customer base. After the payout, the attributable gas sold for the current period was 2,897mmscf (1,736mmscf last time) which was 81% of the gross gas sold due to the timing of the payout. Going forward, the attributable sales will be 60% and then 57% so there will be a further significant production in 2017.
The global recovery of the oil price has resulted in reduced pricing pressure as competitive energy alternatives have increased in price, and has also resulted in improved pricing on the condensate sales. The average gas sales price for the period was marginally lower than the prior period, however, due to the larger proportion of revenue generated by ENEO.
During the year the Logbaba project reached a production milestone after which GDC will now share 40% of revenues generated with RSM which has had a significant impact on the group’s revenue, performance and cash generated in the year. In addition, the concession agreement governing the block grants the Cameroonian State an option to acquire a 5% participation. When they formalise this option to participate in the project, the group’s interest will be reduced to 57%.
In the prior period the group raised a provision for $5M for the reserve bonus payment and disclosed a contingent liability for an additional $5M pending the outcome of the mediation. The mediated settlement, which included the termination of the 1.2% royalty, resulted in a final liability of $11.2M with $5M having been paid during 2016 and the balance over the next two years which resulted in a loss of $2.6M during the period.
Also, the group disclosed a contingent liability of $1.6M in the prior period relating to a land claim submitted in Cameroon. This matter has not been fully resolved but developments has led management to raise a provision of $900K in the current period with a further $700K remaining contingent on the outcome.
During the year, the group added 15km to the Bonaberi line. Prior to the year-end, three new thermal customers were consuming gas along the extension and branch lines were commissioned up to PRMS units to four additional customers, three of which have since completed their downstream installations and are now consuming gas. Further customers along the line are at varying stages of readiness to consume gas soon.
The Logbaba and Bassa power stations have consumed gas in accordance with the seasonal take or pay levels set out in the initial two year contract which expired in April 2017. Negotiations for the renewal of this contract, in conjunction with the provider of the gas fired generators, have progressed well, but at the reporting date had not been concluded. The parties have agreed to continue trading on the current terms until the negotiations are concluded.
The group continues to seek solutions to the power generation requirements of their industrial customers. Those who were party to the original retail power contracts that included the rental of gensets have now sourced or are in negotiations for their own generators and the group will continue to supply gas. They have held discussions with additional potential large off-takers and other grid power products but they need to increase their reserves to supply these large customers before long term supply contracts can be agreed.
One of the Logbaba wells, La-106, has not produced to its potential due to mechanical and borehole damage to the bottom of the well which has continued to date. Despite remediation efforts, which finished in 2016, the well is now seen as an occasional producer for short periods of time when La-105 is undergoing maintenance. Accordingly the board has decided to write down the $22.7M carrying cost of this well.
The 2016/2017 drilling campaign was designed for two wells – La-107 and La-108 in the onshore Logbaba field to supplement the two existing production wells, La-105 and La-106. The drilling programme, which experienced a delayed start, is progressing despite some challenges. Over 125m of gross gas bearing sands have been encountered in La-108 which is significantly more than the 85m found in La-105 in 2010. The completion of the drilling programme will trigger the processing plant expansion project to double the plant capacity to 40mmscf/day so that the group can take advantage of some of the bigger and longer term supply opportunities in the region.
After the year-end, the well control and drill pipe issues, couple with the planned La-108 sidetrack have resulted in a schedule slippage and an estimated budget increase of about $8M, taking the expected cost to complete both wells to about $56M. Planned completion of the well is now Q3 2017 and the group’s share of well costs will be covered by cash generation, existing cash and credit facilities. Installation of temporary flow lines to connect the two wells to the processing facility on completion of the well testing are almost complete and construction on the permanent flowlines will start once the rig is removed.
In February 2016 the group announced a 75% interest assignment of Logbaba’s neighbouring licence area, the 1,235km2 Matanda block from Glencore. Three wells drilled in the field and seismic data show a strong geological continuation between Logbaba and North Matanda. Work is ongoing to evaluate the gas potential of the block in order to identify drilling prospects.
After the year-end, the group announced that it had entered into a Farm Out agreement with Bowleven in relation to the Bomono production sharing contract. The assignment is still subject to government approvals but once completed will result in the group having an 80% working interest in the 2,237km2 license. In 2016 Bowleven completed extended flow tests on the Moambe well that exceeded 7mmscf/day. The intention is for gas to be produced from the Bomono PSC to be fed into GDC’s pipeline network which is only 8.7km away from the drilled wells.
Bowleven will remain as the operator and an 80% participation holder. The deal includes VOG installing a pipeline connection from the Moambe well to the existing network and completion of civil engineering works at the wellhead necessary for the gas processing plant installation, the cost of which is estimated at $6M; a 3.5% royalty from the group’s Bomono production share of hydrocarbons with a cap limiting the total payment to $20M; and £100K of the company’s shares. The work programme, which includes the drilling of one well in the period of the provisional exploitation license commits the group to an estimated $8M.
During the year Robert Palmer and Grant Manheim retired from the board. Andrew Diamond was appointed as Finance Director and Roger Kennedy as a non-executive director.
At the year-end the group had a $1.8M net cash position with cash plus debt headroom of $30.8M. The anticipated spend on the drilling programme in 2017 is $16.9M.
On the 26th June the group announced that it had extended the current gas supply agreement with ENEO. The take or pay components will remain in place and until the year-end an interim gas price of $7.50/mmbtu has been agreed. They are now working with ENEO to create long term solutions.
On the 28th June the group released a drilling update. In well La-108, about 100m of net gas-bearing sands have been encountered and well logs on La-107 so far indicate net 35m of high porosity gas bearing sands in the Upper Logbaba formation. Drilling on La-107 will continue, targeting the base of the Logbaba sands. On reaching this target the well will be logged before being put into production. A 300m high pressure flowline from the well head to the processing plant has been installed and production is expected in Q3.
The net sands for far encountered of 100m in La-108 and 35m in La-107 have exceeded expectations and compared favourable to the 54m encountered in primary production well La-105. Planned completion of both wells is now Q3 2017.
On the 4th July the group supplied an update on the Logbaba participation agreement and the Bomono project. They have signed an agreement whereby VOG has 57%, RSM has 38% and the government has 5%. The government is entitled to a 5% share of revenues from the sale of all hydrocarbons from the project and are also liable for 5% of exploitation costs.
The group also exercised its option to extend the termination agreement of the Bomono farm out with Bowleven to September 2017. Both parties wish to pursue the farm out and are working with the government to progress the project.
On the 14th July the group announced that CEO Ahmet Dik purchased 19,220 shares at a value of £10.7K. He now owns 948,749 shares.
On the 31st July the group released a Q2 operations update. There was an 11.9% increase in gross average gas production from Logbaba to 14.59mmscf/d and gas sales increased to 1,192mmscf for the quarter but the 708mmscf attributable to Victoria was lower than the 996mmscf in Q2 last year due to the change in attributable revenues. The group received $7.8M of net revenue, down from $8.1M in Q1; there was a $7.6M cash position and a $20.7M net debt position at the end of the quarter, compared to $10.7M at the end of Q1. In June the government executed their right to a 5% participation interest in Logbaba, resulting in the group’s interest decreasing to 57%.
At the end of Q2, a 7” liner was run and cemented in well in La-107 at 2,440m MD. After the period-end, the well has continued drilling to a current depth of 2,914m. As previously announced, it has so far encountered a net pay of 35m of high permeability, high porosity gas bearing sands in the Upper Logbaba Formation, slightly more than was expected. In the hole section that is currently being drilled, preliminary data indicates that about 15m of net gas sand has been encountered.
The drilling programme has taken longer than expected due to the problems encountered in well La-108 but first well completion, at La-107, is targeted for Q3 with flow testing and tie in to the process plan expected at the same time. Following commercial completion of La-107, sidetrack drilling will restart at La-108 where about 100m of net gas bearing sands have been encountered between the top of the Logbaba formation at 1,670m and at 2,702m. This programme will allow the group to bring gas online imminently for sale from La-107 and then develop further capacity from La-108.
During the quarter, the group announced that it had extended the current gas supply agreement with ENEO until the end of December. The parties are currently developing the technical and financial elements of a long term gas supply arrangement aimed at increasing the current contractual power supply of 50MW to beyond 100MW.
The take or pay components will remain in place until the year-end, an interim gas price of $7.50/mmbtu has been agreed. Once the La-107 flow test is complete, the group is confident it will execute a number of long term high volume gas supply agreements with local companies.
On the 17th August the group announced that well La-107 had been successfully drilled to its planned TD of 3,180m where the base of the Logbaba formation was encountered. Production completion is now starting, after which the rig will be released form the well. Primary analysis of the logs indicates that they have encountered 35m of net gas sand in the Upper Logbaba formation, as previously announced, plus 23m of net gas sand in the Lower Logbaba formation.
The production test is expected to start in September and by the end of the month, the board expect that it should be tied in as a production well. Following its release, the rig will skid to well La-108, where sidetrack drilling will restart. The group’s plan is to progressively develop additional gas supplies from wells La-105, La-107 and La-108 over the next six months. Following the flow tests from La-107, this well can then be placed into production to supplement gas from La-105 and the board believe that the additional reserves will enable them to conclude longer term contracts with Douala based high usage gas customers.
The new gas supply from La-107 is expected to come online in Q3. This is a very positive outcome (finally!) but I am not sure it will really change much. Still, this is looking like a better investment than the other gas company I have been looking at, Wentworth and I am tempted to take a small punt.