Tullow - Will they kick the barrel down the line?
All,
We have updated our model slightly here.
See below for a summary of changes.
We had been surprised that the RBL lenders agreed to extend the facilities without entering into negotiations with bondholders over upcoming maturities. While the RBL Facility holders maintain control of their destiny with covenant test and 18-month liquidity test in Autumn 2021, they have handed the current negotiations over to the convertible holders. The Company now needs to find a resolution to the two upcoming bond maturities, ($300m convertible and $650m Senior Notes) and without the negotiation stick of the RBL approval, have weakened their hand.
Option 1 - straight refinancing with partial repayment
The simplest solution is a straight refinancing with partial debt repayment. A new $700-800m deal with 7-9% coupon, 5NC2 should be achievable with $150-250m debt reduction from cash on the balance sheet. Alternatively, there could be a convertible component. This is our base case scenario.
Any debt reduction greater than $300m and Tullow’s ability to continue investing in drilling CAPEX, which ultimately drives EBITDA, cash flow and equity value, is compromised. This is why there is an argument that the convertible holders should prefer a lower cash repayment depending on the strike price, as the cash available for CAPEX will drive their equity option.
Option 2 - Pay down $300m convertible and play for time
Paying back the convertible bonds, and reducing the RBL facility in October 2021 to $1.2bn should leave the business at year-end with $450m cash facing upcoming bond maturity in April 2021 of $650m (plus a further $211m reduction in RBL facility). This would be a high-risk move by management to present the 2022 and the RBL lenders with a fait accompli.
The advantage would be that by Autumn, the Company will have clarity over the initial 2 of the 4 wells to be drilled in 2021, and the level of boepd from each well. Bullish estimates are c. 16k boepd from the first two wells, twice our modelled assumption. An extra 8,000 boepd, at current oil prices of $62/bbl equates to c.$150m of additional EBITDAX and cash flow. Under this bull case scenario, a refinancing in late Autumn might be easier to achieve and less complex.
Moreover, any further asset sales (Kenyan operations most likely) have time to come to fruition. We value the Kenyan fields at c.$200-250m and the Company has previously outlined this asset as likely to be sold. The farm-down process was suspended in mid-2020 following discussions with the partners, but we fully expect talks are continuing with JV partners in efforts to realise the asset value.
Positioning
Our base case scenario is Option 1 - a partial repayment and extension/refinancing. Under this scenario, all three legs of our trade should appreciate in value, with the 22’s most obviously benefitting. The equity and the 2025’s should also benefit significantly as it removes near term maturity wall.
Volatility comes from Option 2, the barrel is merrily kicked down the line. This is likely to be neutral at best for the 22’s (although they become the fulcrum class) and the 25’s and equity could potentially trade down on lack of clarity. However, we maintain our fundamental view of asset coverage and cash generation, which should facilitate a deal prior to the 2022 maturity.
We are therefore maintaining our 3% position in the 2025 bonds, a 2% position in the 2022 Notes and a 4% equity position.
Happy to discuss,
Tomás
Model changes
We have flattened the oil price curve increasing the achieved price for FY21 to current levels, but stabilised the FY22 and FY23 levels to $63/bbl and $65/bbl respectively. But in truth, although important inputs, the bigger impact on EBITDA and cash flow remains production levels.
We have adjusted the production levels for the sale of the Equatorial Guinea and Gabon assets, and adjusted the decay rates of existing wells following conversations with the Company. However, the biggest driver of the production levels is the impact of the new wells currently been drilled in Ghana. Our assumptions are cautious (especially versus Company guidance) and this is the biggest influencer on EBITDA and cash flow. We maintain a higher OPEX level than Company guidance due to the production issues the Company experienced in Ivory Coast in January.
IN relation to decommissioning liabilities, we have reduced the overall decommissioning liabilities in line with the disclosure in the Annual Report. However, it should be noted the Company has increased the guidance on decommissioning expenditure for FY21 and FY22 due to increased scope in Mauritania decommissioning, expected to be completed in FY22.
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E: tmannion@sarria.co.uk
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www.sarria.co.uk