LB - 13 valuation P90
Please take into account that this valuation has been compiled using ONLY the P90 net value of 305Mmbbls to COPL, adjust accordingly to allow for P50 or P10.
POO (price of oil) of $50 has been ascribed , adjust accordingly.
Canadian Overseas Deepwater Water Mesurado-1 Valuation
Liberia Block LB-13 Terms:
Operator - Exxon Mobil 83% Working Interest.
Canadian Overseas - 17% Carried Interest until $120m has been expended on drilling costs.
NOCAL - to receive a 10% participating interest at the start of commercial production. **NOCAL PI not incorporated in this valuation**
All other JV costs capped at $1m run off until 100% of all drilling costs have been completed.
The current preliminary volumetric prospective recoverable resources on LB-13 Mesurando-1 prospects (at all geological strata) assigns a total prospectivity ranging, at a minimum, from 1797Mmbbls P90 (Gross) – 4,238 Mmbbls P10 (Gross). For the purposes of this valuation, I have employed the more conservative prospective resources estimate of 1797Mmbbls P90 (Gross), of which therefore, 305Mmbbls will net to COPL as per the PSC terms.
The $120m free carry that COPL has under the PSC with Exxon Mobil, should realise 2 exploration wells @ +/- $65m per well.
Assumed Development Expense
Asset
Liberia LB-13 Total Development Expense TDE) COPL Share of TDE
COPL 17% 20 appraisal & production wells COPL’s wells/infrastructure
Holding @ $45m per well = $900m ¹ (17% obligation = $153m
Sub Total $900m $153m
Total Development cost is $900m ***COPL obligation = $153m***
¹ The number and cost of wells is an estimate which serves as a proxy value to include, beyond appraisal & production wells per se, installation costs of subsea infrastructure , FPSO, etc.
Capex refund and “Cost Oil” considerations
Companies appreciate PSC regimes not only because of the surety of contract it supplies, but because of the cost oil concept operative during the entire exploration and production phases. This guarantee, subject to broadly similar refund formulae (known as the “r factor”) across the world, the terms and speed which investment costs (ie -capital expenditure) are returned to investing party/contractor. Usually, most of the sunk costs is included and paid back (especially insofar as total exploration costs are concerned) within a short period of time out of production revenue from day one of production, as a percentage of that income.
Of course this recovered amount is liable to various small transaction costs or levies in the field’s jurisdiction, as well as forms of corporation tax in contractor’s resident jurisdiction.
Accordingly for the purposes of this study, we will assume that 80% of the total investment cost (capex) is returned to investor/contractor. That is consciously a high write-off amount, but best to keep in line with overall liberal expense/conservative revenue approach of this valuation.
Therefore, on the basis of an 80% refund of gross LB-13 Pre- Exploration & Exploration Expense ($127m Exxon Mobil [drilling]/COPL $25m[seismic]), the amount recovered equates to $101m/COPL $20m respectively. Similarly, 80% refund of the gross Development Expense ($900m/$153m) equates to $747m /COPL ~$153m.
Accordingly, the aggregate LB-13 Exploration/Development (E&P recovered costs) under the Exxon Mobil/COPL refund arrangement is ($720m+ $153m) = $873m total, of which ($153m+25m)= $178m represents the capital expense COPL can claim back.
This net recovered capex consideration of $178m forms one constituent of what is known as Cost Oil”, ie items that are deducted as overall costs by contractors in developing an oil field. The other parts, where no refund obligations apply, are those items consisting of the Cost of Capital and the Operating Expenses (Opex).
Cost of capital (Cocap)
Neither the pure exploration costs nor the production expense include the cost of finance capital (loan interests, etc). Funding of course will be scaled over time depending on developments. And certainly much of the total investment can and will be met via other instruments (placings, warrants & rights issues, etc).
Nevertheless;
There will be costs of capital incurred, and in keeping with the stance adopted throughout this study, we will assume this item to be at Libor + 8% and apply to the full gross exploration and production costs incurred by COPL, i.e ($153m x 10% =) $15.3m.
Accordingly the cost of capital for the purposes of this study, amounts to $15.3m = (rounded to $15m)
(The total E&P expense incurred by COPL ($178m) plus it’s costs of capital ($15m) will hence constitute the company’s total net debt = $193m).
Opex
In addition to these capex and cocap items, charges incurred for field and plant maintenance, personnel and general administrative costs, although paid out of annual cash flow throughout the entire life of the field, also fall under the “Cost Oil” mantle. As a rule, this operational expense usually amounts to approximately twice that of the gross exploration/production expense.
Accordingly for the purposes of this study, these Opex costs as they pertain to COPL amount to ($178m x 2] = $356m
Annual POO (Price of Oil) Assumptions
The prospects for any price upturn currently look bleak, given the on-going downward trend in the oil price cycle the industry is witnessing, with only modest recovery seen once the cycle turns upstream in the future. Given the lower future fossil fuel demand resulting from greater energy efficiencies in industry, transport and heating, as well as the impact of Renewables, there is scepticism about any future return to three figure prices per barrel.
Accordingly, although the 2% yearly growth in the annual price value assumed by RPS will be maintained until 2025, it will be then reduced to 1% until 2035 and dropped to 0% thereafter. A 50% discount to the reference RPS figure will be used for 2016, decreasing to 45% for 2017 and maintained at 40% until 2035, whereas it will be increased again to 45% for the remaining timespan, reflecting the start of another downwards cycle in the price of oil. These variables will be employed for the additional 7 years (to 2038) to incorporate a 20 year field life and hence go beyond the 2010 RPS 20 year forecast, given that first production from LB-13 could potentially begin as early as 2020.(POO figures – while conservative - are broadly in line with those currently put out by other forecasters)
Year RPS 2010 Base Case Brent $/b 2016 Brent Forecast $/b
2015 92.91 53.55
2016 94.77 47.39
2017 96.66 53.16
2018 98.60 59.16
2019 3 100.57 60.34
2020 102.58 61.55
2021 104.63 62.78
2022 106.72 64.03
2023 108.86 65.32
2024 111.03 66.62
2025 113.25 67.95
2026 115.52 68.63
2027 117.83 69.32
2028 120.19 70.01
2029 122.59 70.71
2030 125.04 71.42
2031 - 72.13
2032 - 72.85
2033 - 73.58
2034 - 74.32
2035 - 74.32
2036 - 70.60
2037 - 67.07
2038 - 63.72
(3) Year of first production. $50/b is viewed as the necessary basis for LB-13 profitability.
Enterprise Value Assumptions
a) - In order to arrive at Enterprise Value (EV) and ultimately Fair Value (FV) for the LB-13 project the following (crude) model is used. I understand that the 10% royalty input and the40% tax burdens (0-100,000 bopd)and Profit Oil maximum return are – I understand - those foreseen in the LB-13PSC.
1) - Oil produced and saved = 100%.
2) - Minus Royalty = 10%
3) - Available crude oil = 90%
4) - Minus corporation & withholding taxes (40%) plus other transaction costs (roughly 4%) = 46%.
5) - Minus Cost Oil (recovered capex,+ cocap + opex)
6) - Profit oil = (46%) of oil produced and saved minus Cost Oil. (Under existing PSC, profit oil cannot exceed 60% maximum of oil produced and saved allowed for contractor).
Therefore, as this model applies specifically in the LB-13 case:
1) - Crude Oil produced and saved = 305Mmbbls (100%).
2) - Minus (10%) Royalty = 30.5 Mmbbls (2%)
3) - Available crude oil = 274.5Mmbbs (90%)
4) - Minus Taxes et al = 140.3Mmbbs (46%)
5) – Minus Cost Oil { recovered capex ($178)m + cocap ($15m) & opex ($356m)} = $549m
6) - Profit oil = 140.3Mmbbs minus $549m
Therefore, COPL’s net undiscounted entitlement of prospective 305Mmbb LB-13prospective recoverable resources = 140.3Mmbbs minus capex, cocap and opex ($549m).
EV is subject to standard refinements so as to arrive at Fair Value and finally, the Price per Share (PPS). The number of (fully diluted) COPL shares stands at 914,000,000 as of November 2016.
The respective discounted EV is calculated bearing in mind that production is not lineal but tends to be greater in early years and drifts down towards the end of the field’s life span (20years):
Accordingly, COPL’s Net Oil prospective Resources entitlement; 140.3Mmbbs (20year life of field) X $50 (POO) minus Cost Oil $549m= $6,466,000,000
In other words, COPL’s EV (or NPV) from LB - 13 prospective resources = $6,466,000,000
Fair Value & PPS
Enterprise value is not fair value. To calculate that, one deducts from EV the gross company debt ($193m plus the cost of capital $15m) and divides this figure by the number of fully diluted shares outstanding.
PPS = EV-(Debt +CC)/# Share Count).
EV = $6,466,000,000
Net Debt = {$193m + $15} = $208m
Fully diluted share count = 914m (rounded)
Therefore PPS = ($6,466,000,000 - $208m/914m) = $6.84