Rockhopper Exploration — Sea Lion thoughts and Ombrina Mare

Ombrina Mare was discovered in 2007 by Mediterranean Oil & Gas and is 100% owned by RKH following its acquisition of MOG in 2014. The Italian fiscal regime (4-7% royalties, 28% corporate income tax) and estimated 2C recoverable (overwhelmingly oil) reserves of 26.5-40mmboe (95% 17-19° API oil) combine to make it a potentially lucrative project. An appraisal programme would be required (potentially adding material prospective resources in the process), but an indicative development plan in 2014 envisaged 10mboe/d peak production using 5-9 production wells. As such, the prohibition to drill within 12 nautical miles from Italy’s coast, dictated by the re-introduction of the Budget Law in early 2016, stops the development of a valuable asset.

It is RKH’s contention that Italy’s action contravened the Energy Charter Treaty (ECT), which was introduced in 1998 to provide a stable platform for energy sector investment in Europe. It is therefore seeking lost profits.

It is not clear on what basis lost profits are made in the legal case – whether this would be on a gross unrisked basis, and under what assumptions of production, oil price, costs and discount rate. However, it is clear that Ombrina Mare had the potential to become a very significant asset for Rockhopper with current gross NPV10 of over $150m.

We have an indicative model on Ombrina Mare with first oil in 2020 (which assumes that an appraisal/development programme would have been initiated in 2016 (or before)), capex of $20/boe and opex of $15/boe, resulting in a value of $8/boe based on a 10% discount rate. For comparison, this would fall to $6/boe at a 12.5% discount rate. These assumptions are from work in 2015 and have not been adjusted to reflect lower service and capital costs due to the falling oil market, so could well be understating the value. For comparison, a $5/bbl decrease in capex would see an increase to $11/boe (on NPV10). It should not be forgotten that the values increase markedly as production nears, with NPV10 values of $21/boe in 2020 – implying a gross block value of over $500m (although bear in mind this value is after a significant capital spend).

We would expect Rockhopper to have looked to farm-down its interest in any development, reducing its 100% working interest in return for a carry on development. Depending on the commercial arrangement that could have been reached, we would expect Rockhopper would have been able to retain the majority of value in this case.

The company has entered into an agreement with a third party to fund the litigation, which should allow it to retain “a very material proportion of any award.” We make no estimate of potential awards at this point and expect the process may take years.

For valuation purposes, we would cautiously assert that investors may look to include some of this potential in their expectations. Until we hear further from the company, we tentatively assume that Rockhopper is seeking lost profits of current NPV10 $150m – we choose to include 25% of this value and discount it by two years, equating to 5p/share. We are aware that these are estimates and open to material uncertainty.

After the work that Premier has done in reducing probable costs for Sea Lion, the economics of the project have improved. PMO indicated that the likely capex has fallen to $10/bbl while opex has fallen to $15/bbl and this has reduced the 2018 NPV10 breakeven to around $45/bbl (as we model, it is around $42/bbl flat).

We take a more conservative approach with costs, but even so the IRR increases to 20% at $50/bbl and 24% at $55/bbl (on a flat basis). At our base case long-term assumption of $70/bbl on a real basis, the gross project IRR is as large as 46%.

Given these results, it is reasonable to assume that the project would be sanctionable now if it was under a well-capitalised operator. A summary of the returns/IRRs at different oil prices is below.

Gross project NPVs at these oil prices are attractive. Note that the RKH/PMO relationship splits this NPV (at FID) on a 50:50 basis at the moment.

These numbers imply that unless one were to take a fairly pessimistic view on the macro (either that the costs indicated are too optimistic or that oil prices remain below current levels for the duration of the project), an operator would (we would suggest) look to sanction the project.

This picture is slightly modified for any incoming partner. They would take on a disproportionate capital burden (through a carry), but returns still suggest that Sea Lion is an attractive project (even if only looking at Phase one in isolation). The picture improves if we account for Phase two and any Isobel Deep exploitation.

The Sea Lion development is currently dependent on PMO’s ability to finance the capex. The combination of the falling oil price and high capital investment led to a worsening net debt situation over the recent past leading to an inability to fund further significant investment (and certainly not of the scale required for Sea Lion).

According to PMO, it will not get back to a net debt/EBITDA ratio of less than 3x until 2018 (and 2x until 2020). Unless the company finds alternative ways to finance the investment, it appears that PMO cannot afford to develop Sea Lion as currently structured.

Examining the capacity to generate reserve-based lending (RBLs), we assume a $50/bbl Brent deck and apply the field-life and loan life NPVs to calculate the amount of capital that could be raised pre-first oil (after taking into consideration a capex add-back). We model loan life cover ratio (LLCR) of 1.4x, field life cover ratio (FLCR) of 1.3x, and a discount rate of 7%. Under these conditions, unless the tenor (time to maturity) of the loan is greater than four years, no significant RBL facility would be available before 2020, although RBL facilities do become more material as production nears. Exhibit 6 indicates how variations in the assumptions affect the 2019-22 lending facilities. Debt providers could well be using different assumptions to those above.

The lack of RBL in early years is common – typically equity funding (of around 40%) comes first before debt can be drawn.

As a result, we look at how various financing mechanisms mentioned by PMO may affect the receiver of cash flows from Sea Lion and therefore value to RKH shareholders.

For the sake of transparency, we have undertaken the analysis below on the basis of the gross project, rather than from the current viewpoint of RKH or PMO. Getting the project to FID is likely to involve amending the current arrangement and it may be in RKH’s interest to sacrifice some value (via working interest, carry or other means) to ensure the project proceeds. The current agreement for Phase 1 has working interests standing at 40% RKH:60% PMO. While RKH benefits from a material capex carry, it pays PMO guarantee fees (out of cash flows) that will adjust the NPV at FID to a 50:50 split.

As a result, while a deal to provide third-party financing should in theory only hit PMO’s bottom line (since it is due to carry the capital investment in Phase 1), the current agreement whereby NPV is shared suggests that some of any value lost/gained through this process is shared with RKH.

We look at the effect of a number of structures on Sea Lion’s project value:

For simplicity, we only examine the effects on Phase 1 to reduce the complicating factors that Phase 2 inclusion may present: (i) the differing working interests in Phase 2 (where RKH holds a 64% WI in PL04); (ii) the existence of Isobel Deep which could be as large as Sea Lion (pending proper appraisal, according to the company); and (iii) the vastly different financial positions that the partners should have as Phase 1 comes on stream and cash flows result.

We have studied a number of recent deals with development carries and generated implied IRR for the incoming party. Two recent deals are particularly germane for Sea Lion: the development deal executed by Ophir with OneLNG and the sale of a portion of Tullow’s (Uganda) interest to Total (and now CNOOC following pre-emption exercise). As the chart below indicates, these imply an IRR for the buyer of around 20% (based on oil price expectations at time of the deal).

For the purpose of this analysis, we assume that $500m of capex is carried over a period of years (pre-first oil), with a percentage of project cash flows then flowing to achieve a targeted return. In this case, we assume the return is 25%. This is higher than many of the other deals, so it is likely a conservative scenario. In this case, the third party would receive 17% effective interest in Phase 1 cash outflows (in return for supplying about 33% of upfront capex).

Export credit is a system by which quasi-governmental institutions (credit agents) act with governments to provide finance normally in the form of support to exporters. This can take the form of direct lending or guarantees to support commercial bank lending. It is likely given their respective sizes that PMO/RKH would not be sufficiently large/have a good enough credit rating to guarantee the revenues for an FPSO build, for instance.

Typically, these loans would require certain conditions to be met, such as the location where equipment is manufactured. This may mean that some plans for the development may require adaption. We would note that that loan finance available for this kind of spending would be favourable and provide for a significant percentage of the value of such a purchase, it could mean overall costs are not affected by much.

There is uncertainty over how this structuring would work, so for illustrative purposes we model a loan of $500m with an 8% interest rate. This would require effective ring-fencing of around 9% of the Phase 1 project cash flows.

At high oil prices, Falkland Island fiscal terms are relatively generous, with a 9% royalty and 26% corporate income tax. However, these are inflexible as in lower oil price environments, the royalty component becomes more onerous as it acts as revenue tax and would be payable from first production, unlike corporate income tax, which is only payable after historical losses have been offset by production. PMO stated at its full-year results presentation that it was “working with the Falkland Islands government to look at fiscal terms that will enable the project to go forward”. We would be surprised if the close co-operation between the partners and the Falkland Islands over the last few years had not examined ways that the project could be brought forward to get to first cash flows sooner. While this is perhaps more finely felt by shareholders (given their higher discount rates than the FIG), the cash flows are also important for the population of the islands. There should therefore be some appetite for negotiations on both sides.

We would expect any movement to focus on royalty rates flexing with oil prices (rather than corporate income tax rates), with a lower rate for oil prices less than a threshold (say $50/bbl), with compensating increase to royalty rates if oil prices move higher (say $80-90/bbl). This better balance incentives and rewards to get the project moving forward.

For illustration, we show below how these changing rates (without thresholds over oil prices) affect gross project NPV (for contractors) and government revenues (undiscounted).

Given the nature of the analysis and the unknown nature of any eventual deal, we have excluded a number of factors which would, with fuller information and data, normally be included.

At this stage, we have kept the analyses separate and note that the effect of mixing two or more of these structures may not necessarily result in the same NPV as simply adding together the individual effects, particularly, for example, due to tax effects.

WACC – we assume a constant discount rate to evaluate the project cash flow in this analysis. In reality, increased debt funding (to a certain limit) will reduce the WACC of the companies, driving up project value. Higher corporate tax rates increase the benefit of tax shielding of debt but reduce the post-tax cash flows, while the effect of changes to royalty rates are not captured by WACC but are key to any renegotiations over changes (particularly for revenues to the Falkland Islands) and may affect initial debt capacity and interest rates applied.

We have tweaked our modelling assumptions, given PMO’s statement (in the conference call to its recent full-year results) that it has been successful in further reducing costs (to $15/bbl for opex and $10/bbl for capex). We remain above guidance on both opex (falling from $23/bbl to $18/bbl life of field) and capex (unchanged at $13/bbl) for the moment but this reduction has the effect of increasing the value for Sea Lion, reducing NPV10 breakeven and making the project more attractive for industry partners and investors.

To balance this, the likelihood of RKH sacrificing some of its value to help get the asset developed in the timelines we currently assume, is relatively high. It is not clear what form this might take, nor how much could be sacrificed. We already apply a fair degree of risking to Sea Lion to account for the uncertainty. Normally, in fields as well appraised as Sea Lion and with FEED ongoing, our risking would be 50% or more, but we have been using a risk factor of 25% for Phase 1 and 20% for Phase 2. We introduce a further risk of 80% to these numbers to account for possible value leakage to get a deal done (mirroring the possible impact of a third party/service company requiring a high IRR for entry), which reduces our valuation. Investors may also see this risking as a mechanism that roughly equates to the NPV impact of a (roughly) two-year delay in our modelling of first oil in 2022.As discussed earlier, we also include a risked valuation for Ombrina Mare, which adds 5p/share. These changes offset each other, leading to an unchanged NAV of 73p/share.

RKH remains in good financial health with around $60-65m in cash at the end of 2016 (adjusting for post period payments for 2016 activities). Cash flows from Egypt and Italy should largely offset G&A spend in 2017 and other capex spend is relatively light (spread between FEED activities at Sea Lion, a well in Egypt and abandonment costs in Italy). We forecast year end 2017 cash to be around $50m.

We note that it may be a number of years before a decision comes from the Ombrina Mare arbitration. If won, the resulting award may increase Rockhopper’s cash reserves markedly. If our assumptions on value of claims are fair, the award could be larger than the current market capitalisation of Rockhopper.