7.  OIL AND NATURAL GAS PROPERTIES AND EQUIPMENT

Extension of Term of Etame Marin Block PSC

On September 25, 2018, VAALCO together with the other joint owners in the Etame Marin block (the “consortium”) received an implementing Presidential Decree from the government of Gabon authorizing a Sixth Amendment (the “PSC Extension”) to the Etame Marin block PSC.  Our subsidiary, VAALCO Gabon S.A., has a 33.575% “Participating Interest” (working interest including the working interest attributable to the carried interest owner) in the Etame Marin block.  

The PSC Extension extends the term for each of the three exploitation areas in the Etame Marin block for a period of ten years with effect from September 17, 2018, the effective date of the PSC Extension.  Prior to the PSC Extension, the exploitation periods for the three exploitation areas in the Etame Marin block would expire beginning in June 2021.  The PSC Extension also grants the consortium the right for two additional extension periods of five years each.  The PSC Extension further allows the consortium to explore the potential for resources within the area of each Exclusive Exploitation Authorization as defined in the PSC Extension. 

In consideration for the PSC Extension, the consortium agreed to a signing bonus of $65.0 million ($21.8 million net to VAALCO) payable to the government of Gabon (the “signing bonus”).  The consortium paid $35.0 million ($11.8 million net to VAALCO) in cash on September 26, 2018 and paid $25.0 million ($8.4 million net to VAALCO) through an agreed upon reduction of the VAT receivable owed by the government of Gabon to the consortium as of the effective date.  An additional $5.0 million ($1.7 million net to VAALCO) is to be paid in cash by the consortium following the end of the drilling activities described below.  We have accrued our $1.7 million share of this remaining payment as of September 30, 2018.  The amount paid through a reduction in VAT has been recorded at $4.2 million which represents the book value of the receivable, net of the valuation allowance.    We have allocated our share of the signing bonus between proved and unproved leasehold costs using the acreage attributable to the previous exploitation areas and the additional acreage in the expanded exploitation areas resulting in $10.9 million being attributed to proved leasehold costs and $6.7 million attributed to unproved leasehold costs.

Under the PSC Extension, by September 16, 2020, the consortium is required to drill two wells and two appraisal well bores.  We estimate the cost of these wells will be approximately $61.2 million ($20.5 million, net to VAALCO).  If the wells are not drilled, then the consortium must pay the difference between the amounts spent on any wells that were drilled and the estimated costs of the wells as set forth in the Work Program and Budget as approved by the government of Gabon.  The consortium is planning to drill these wells in the second and third quarters of 2019.  The consortium is also required to complete two technical studies by September 16, 2020 at an estimated cost of $1.3 million gross ($0.4 million net to VAALCO).

Prior to the PSC Extension, the consortium was entitled to take up to 70% of production remaining after the 13% royalty (“Cost Recovery Percentage”) to recover its costs so long as there are amounts remaining in the Cost Account.  Under the PSC Extension, the Cost Recovery Percentage is increased to 80% for the ten-year period from September 17, 2018 through September 16, 2028.  After September 16, 2028, the Cost Recovery Percentage returns to 70%.  

Prior to the PSC Extension, the PSC provided for the government of Gabon to take a 7.5% gross working interest carried by the consortium.  The government of Gabon transferred this interest to a third party.  Pursuant to the PSC Extension, the government of Gabon will acquire from the consortium an additional 2.5% gross working interest carried by the consortium effective June 20, 2026.  VAALCO’s share of this interest to be transferred to the government of Gabon is 0.8%.

Depletion and Impairment

Depletion of wells, platforms, and other production facilities are calculated on a field basis under the unit-of-production method based upon estimates of proved developed reserves. Depletion of developed leasehold acquisition costs are calculated on a field basis under the unit-of-production method based upon estimates of total proved reserves.  Support equipment and leasehold improvements related to oil and natural gas producing activities, as well as property, plant and equipment unrelated to oil and natural gas producing activities, are recorded at cost and depreciated on a straight-line basis over the estimated useful lives of the assets, which are typically five years for office and miscellaneous equipment and five to seven years for leasehold improvements.

We review our oil and natural gas producing properties for impairment quarterly or whenever events or changes in circumstances indicate that the carrying amount of such properties may not be recoverable. When an oil and natural gas property’s undiscounted estimated future net cash flows are not sufficient to recover its carrying amount, an impairment charge is recorded to reduce the carrying amount of the asset to its fair value. The fair value of the asset is measured using a discounted cash flow model relying primarily on Level 3 inputs into the undiscounted future net cash flows. The undiscounted estimated future net cash flows used in our impairment evaluations at each quarter end are based upon the most recently prepared independent reserve engineers’ report adjusted to use forecasted prices from the forward strip price curves near each quarter end and adjusted as necessary for drilling and production results.

There was no triggering event in the third quarter of 2018 that would cause us to believe the value of oil and natural gas producing properties should be impaired.  While there were capital expenditures during the quarter related to the signing bonus for the PSC Extension, the value of the extended exploitation period and the increase in the Cost Recovery Percentage exceeded the consideration given.  Other factors considered included the fact that the future strip prices for the third quarter of 2018 modestly increased from the second quarter of 2018, and there were no indicators that downward adjustments were needed to the 2017 year-end reserve report.  With respect to current reserve estimates, we estimate that reserves have increased as a result of the PSC extension and the wells planned for 2019.

There was no triggering event in the third quarter of 2017 that caused us to believe the value of oil and natural gas producing properties should be impaired.  During the third quarter of 2017, prices remained stable and we incurred no significant capital spending.  We considered these and other factors and determined that there were no events or circumstances triggering an impairment evaluation for all of our fields.