Notes From The Field - An English Law Perspective On The Oil & Gas Market
In a previous article, we examined the extent to which the uncertainties associated with exploring for and producing petroleum can be mitigated by an upstream company through a divestment of part of its working interest in the concession. Risk mitigation achieved by means of a farm-out assumes that the upstream company is willing to dilute its equity position in its concession interests as a consequence of reducing its exposure to such uncertainty of outcome. A farm-out arrangement, however, will not address the needs of an upstream company that wishes to keep the entirety of its interests in the concession. The provision by a third party of finance sufficient to meet the costs of petroleum exploration or production activities under that concession could be a solution.
This article examines that group of contractual arrangements which create a non-operating interest under a concession, more popularly known as royalties. Royalties are widely used in leasehold-based jurisdictions, such as the US and Australia, which have developed their own distinct transactional frameworks for royalties driven largely by the tax, legal and regulatory environments in those jurisdictions. The focus of this article is on the use of royalties by upstream companies operating outside those jurisdictions. Outside the US and Australia, royalties have historically been used primarily as sweeteners on a farm-out. However, they are increasingly being used by upstream companies as a means by which capital can be raised from a concession, particularly where that concession offers near-term development opportunities (or is in production) and an upstream company is looking to raise additional capital to finance the development of a discovery.
Royalties are typified by the fact that they create no personal liability for a royalty interest owner in respect of a concession, neither entitling nor obliging their owners to participate in oil and gas operations. These non-operating interests allow an upstream company to retain full ownership of the concession interest whilst attracting a financial investment which enables the upstream company to share the economic risks associated with exploring and developing the concession with the royalty interest owner.
In this article we discuss three distinct categories of royalties: the overriding royalty interest (the “ORRI”), production payments (“PPs”) and net profits interests (“NPIs”). The terminology used to describe royalties varies considerably from one jurisdiction to another and often the same term may be used to describe quite different types of royalties. The primary concern for any party looking to enter into a royalty should be to understand the substance of the relationship that it intends to create rather than looking to the nomenclature of that royalty for guidance.
Royalties: the common elements
Typically, the common elements of a royalty, however it is described, are that a third party (the “royalty owner”) agrees to pay a defined sum to an upstream company, as the holder of a concession (the “producer”). In return, the producer grants to the royalty owner a financial interest in the concession (the “royalty”). This royalty is typically represented by the right of the royalty owner to receive a defined share of the produced petroleum from the concession (or a defined share of the proceeds of sale of that petroleum). The royalty owner will not hold a direct ownership interest in the concession and will generally not be obliged or entitled to become involved in the business of producing petroleum under the concession.
A properly structured royalty is not a financing but a sale. The parties enter into a sale and purchase agreement, pursuant to which the producer sells and the royalty owner purchases the right to a share of the petroleum produced from a concession for an agreed price. A separate deed of grant of royalty is also entered into by the parties. It is under this deed that the royalty is created and the terms of the deed establish the basis on which the producer will satisfy its petroleum production obligations to the royalty owner.
Overriding Royalty Interests (“ORRI”)
Under an ORRI-based royalty, a royalty owner agrees to pay a purchase price to a producer and in return the royalty owner is granted the right to a defined share of the gross volume of petroleum that is produced from the concession for the producing lifetime of that concession. The producer receives the benefit of the upfront payment made from the sale of the royalty which it can then apply towards funding the activities under the concession.
The royalty owner under an ORRI assumes the risk that the concession may not produce petroleum at all and also that petroleum production levels may be lower than initially projected. That said, once the concession moves into production, the royalty owner has the assurance that it will benefit from its defined share of whatever can be produced, from first petroleum until production ceases on a permanent basis. The royalty owner bears none of the risk of the cost of producing the petroleum, whether those costs are routine costs, such as operating costs or planned capex or result from unexpected occurrences such as construction cost overruns, increased opex or remediation works arising from a blow-out or other accident.
Production Payments (“PP”)
Under a PP-based royalty the producer receives the same benefit as under other royalty arrangements however the benefit received by the royalty owner from the producer in return for that upfront payment can manifest itself in different ways. A PP can be structured either as a right to a defined share of the petroleum produced from the concession (a volumetric production payment interest, “VPP”) or as a right to a pre-agreed financial amount that will be realised from the sale of the petroleum production from the concession (a dollar denominated production payment interest, “DDPP”). In certain jurisdictions, the creation of a royalty which entitles the royalty owner to a share of petroleum production may expose the royalty owner to liability for decommissioning the concession. These sorts of regulatory considerations may therefore influence a royalty owner when deciding which royalty structure to use.
Whether the PP is characterised in volumetric or monetary terms, the distinguishing characteristic of a PP is that it is limited in time. The PP will continue to exist only until such time as the royalty owner of the PP has recovered either a defined volume of petroleum from the concession or it has recovered a defined financial sum as a result of the sale of the petroleum production from the concession. The PP therefore operates much more closely to a true financial instrument, with the royalty owner of the PP concerned neither with ensuring sustained petroleum production over the lifetime of the concession, nor with the most efficient means of developing the concession. As a consequence, there is less alignment between the interests of the royalty owner and the producer than under an ORRI or an NPI-based royalty.
Net Profits Interest (“NPI”)
NPI-based royalties start from the same basis as the ORRI but require a royalty owner to share more fully in the operational risks associated with a concession. Under an NPI-based royalty, the royalty owner agrees to pay a defined sum to the producer and in return the producer is granted the right to a defined share of the net volume of petroleum that is produced from the concession for the producing lifetime of that concession. This is in contrast to an ORRI or a VPP-based royalty where the royalty owner will receive its share of the produced petroleum on a gross rather than a net basis. The NPI results in the royalty owner assuming not only the risks of non-production or under-performance against the projected petroleum production, but also its proportionate share of the costs of developing and operating the concession and the costs of producing, transporting and marketing the produced petroleum.
The costs that a royalty owner of an NPI will share with the producer will be defined in the deed of grant and will typically be the subject of extensive negotiation. The royalty owner of the NPI may, for example, agree to bear the risk of cost overruns on certain third-party costs but may be less willing to bear the risk of cost overruns where such risks should be capable of management by the producer through good and prudent oil field practice.
The characteristics of an NPI-based royalty mean that it aligns much more closely with a working interest in the concession than a financing one. Firstly, the NPI royalty owner’s share of production is calculated after the deduction of certain overheads incurred in producing the petroleum. This means that where the development of the concession is unprofitable, the royalty owner of the NPI will share (to a greater or lesser extent depending on the negotiation of the costs taken into account prior to the making of distributions under the NPI) this unprofitability with the producer. Secondly, the term of the NPI is co-extensive with the duration of the concession. And thirdly, the royalty owner receives its share of petroleum production on a net basis after the costs of development, operations and production have been accounted for. As a consequence, the working interests of the producer and the financial interests of the royalty owner are much more closely aligned. The result is that, of the royalty interests discussed in this article, an NPI-based royalty creates the closest alignment of interest between the producer and the royalty owner to ensure the sustained and economically efficient production of petroleum from the encumbered concession.
Royalties and Risk Transfer
The risk transfer between the producer and the royalty owner under the various royalty interests described in this article can be summarised as follows:
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A common feature of each of the royalty structures described in this article is that a royalty owner assumes (and shares with a producer) the risk that the encumbered concession contains, and is capable of producing, sufficient reserves to meet the expected rate of return from the concession. The non-recourse nature of the royalty means that the royalty owner is entitled only to look to the petroleum produced from the concession for the discharge of the royalty and has no recourse to the wider resources of the producer. Even where a royalty owner requires the producer to provide security in respect of the upfront payment made to purchase the royalty, such security is typically limited either to security over the producer’s petroleum interests in the ground in respect of the encumbered concession, or security over the concession itself. If the petroleum production from the concession fails to meet expectations, then both the producer and the royalty owner will share in the downside.
For a producer, the non-recourse nature of a royalty can offer a number of advantages. Unlike debt, the royalty typically encumbers only the concession over which it is created, leaving the rest of the producer’s portfolio unaffected in the event that the concession fails to perform in the manner expected. Generally, the producer also assumes no personal liability for the payment or discharge of the royalty, ensuring that the corporate interests of the producer therefore remain untouched. This creates an alignment of interest between the producer and the royalty owner in the production of petroleum from the concession which is often lacking where corporate or portfolio-based financing vehicles are selected.
For a royalty owner, the non-recourse nature of a royalty means that the value of that interest is usually wholly dependent upon the production performance of the concession. For this reason, where a producer wishes to raise capital from the creation of a royalty over a concession, the concession in question will generally need either to offer near-term development opportunities or to be already producing in order to raise significant funds through the sale of a royalty. A royalty owner will try to mitigate this reserve risk by performing due diligence on any concession over which it proposes to take a royalty. Typically this will include the commissioning of an independent reserve report to confirm the petroleum recovery potential of the concession and detailed due diligence into the engineering design of any proposed development.
Notwithstanding the due diligence that a royalty owner will undertake on the concession, the sharing of reserve risk under a royalty could be adjusted in a manner similar to the deferred (or contingent) consideration arrangements that are often put in place in respect of a farm-out of a working interest in a concession. While a royalty owner may prefer to price the upfront payment to a producer conservatively (so as to ensure a minimum return to the royalty owner in all but the most extreme reservoir failure scenarios), such ultra-conservatism is unlikely to be sufficiently attractive to the producer to encourage it to encumber its concession with a royalty. As a result, the parties may consider including an element of conditionality to the royalty paid. A tiered royalty could be created which ensures that a greater share of production is allocated to the royalty owner if certain production milestones are reached. This structure allows the producer to realise a greater upfront payment from the royalty owner in return for the receipt by the royalty owner of a greater share of the petroleum production from the concession if the upside potential in the concession is realised.
The creation of a royalty allows a producer to raise capital and transfer part of the economic risk in the concession operations from itself to a royalty owner without the interference or participation of that royalty owner in the operation of the concession. Where a producer is solely looking to raise additional funds for a development or to mitigate part of its economic risk in a concession, this lack of intrusion by a royalty owner in the day-to-day operations of the producer offers a significant advantage over a traditional farm-out arrangement. There is no dilution of either the working interest or the voting rights of the producer in the concession. This means that the producer may be able to retain the internal value of the concession and even, in some circumstances, continue to book the reserves covered by that royalty.
Typically, the operational constraints imposed by a royalty owner on a producer will be extremely limited. The rationale for this is that royalties create a non-operating, non-expense bearing (other than to the extent assumed under an NPI-based royalty) interest in a concession. In certain jurisdictions, the inclusion of protections under a royalty which insulate a royalty owner from the downside risks associated with the concession may lead to the conclusion that the royalty was intended to operate as a loan rather than the creation of a non-operating interest in the concession. This could affect the nature of the interest taken and result in adverse legal and tax implications for the royalty owner. Examples of these protections might include provisions which have the effect of guaranteeing the royalty owner’s return under the royalty, or where the royalty owner is granted step-in rights (as might a lender) in the event of a default by the producer under the deed of grant.
Where these jurisdictional constraints do not exist, however, certain protections may be granted to a royalty owner. The interim covenants found in a typical sale and purchase agreement or farm-out agreement are often very detailed and aim to protect a buyer or a farming-in party against adverse changes in the value of the interest it is acquiring between the signing of and the completion of a transaction. By contrast, the protections contained in a royalty will typically be high-level and are intended only to give the royalty owner oversight over the potential erosion of the value of its royalty interest. Common covenants include a covenant by the producer that it will maintain its interests in the concession and any associated joint operating agreement and a covenant that it will not transfer its interest in the concession or any associated joint operating agreement without the prior consent of the royalty owner.
The operational controls under an NPI-based royalty may go further. As noted previously, where there is no net profit from the petroleum production under a concession, a royalty owner will receive no revenue. As a consequence, the deed of grant creating the NPI will seek to control or limit the costs that will be borne by the royalty owner. For example, the deed of grant could impose restrictions in respect of sole risk operations, providing that the costs of such operations will not be taken into account for the purposes of the costs shared with the producer under the NPI. Similarly, the royalty owner may seek to impose constraints on the producer’s ability to deduct the costs of intra-group contracting arrangements before applying the NPI, where such arrangements are not on market terms or at market rates. In both instances, it is more typical for these constraints to be structured as a restriction on the ability of the producer to take into account such costs before distributing the net profits from the concession, rather than as an absolute prohibition on such activities. The latter would imply a degree of control by the royalty owner over the producer’s operations, which runs contrary to the concept of a royalty and the interest created thereby.
An additional, but important, protection for a royalty owner will be a right to audit the books and records of a producer to determine the accuracy of any statements or payments made in connection with a royalty. This ongoing due diligence right will be of particular value to the royalty owner under an NPI-based royalty where the royalty owner will want to ensure that only the agreed costs are taken into account before payment of the royalty. As a result, the information undertakings in a deed of grant will often assume greater importance and be the subject of more negotiation than the operational restrictions imposed under that royalty. This is quite at odds to the approach taken in a farm-out.
Commodity Price Risk
Typically, royalty structures pass the commodity price risk associated with the sale of royalty petroleum to a royalty owner. Under an ORRI, NPI or VPP-based royalty, the risk that the production will be sold at a price sufficient to cover the initial upfront payment made by the royalty owner to the producer is borne by the royalty owner. This will be the case regardless of whether there is physical or cash settlement of that royalty.
Where a DDPP-based royalty is entered into by the parties, this allocation is altered. The interest created under a DDPP subsists until a royalty owner has recovered a defined amount of money from a producer through the sale by the producer of the petroleum from the concession burdened by the royalty. Under this formulation, commodity price risk is borne by the producer, whose concession will remain burdened by the DDPP until it has been fully repaid.
Where commodity price risk is borne by a royalty owner, there are a number of mitigants that the royalty owner may use to reduce its exposure to price fluctuation. These could include entering into commodity price hedges to ensure a return that allows the royalty owner to recover at least the initial purchase price of the royalty. Alternatively, where the royalty is settled in cash, the royalty owner may require the producer to enter into a long-term fixed price petroleum sales contract in respect of the production attributable to the concession burdened by the royalty.
Royalties are, by their nature, specific to the concession in question, the jurisdiction in which the concession is physically located and the nature of the relationship that the parties seek to create. This article has highlighted just some of the issues that should be considered by both a producer and a royalty owner when seeking to enter into a royalty.
Royalties offer benefits both to a producer and a royalty owner. They offer a producer the ability to raise capital and to share some of the economic risk of the exploration and production activities it conducts under a concession without dilution of its interest in the concession itself or the interference of a third party in the day-to-day operation of that concession. This may be a particularly attractive option for a producer where the sources of capital funding available to that producer are limited. Similarly, for a royalty owner, a royalty offers the ability to invest in oil and gas concessions, often as part of a wide portfolio of royalty interests, without exposing itself to the potentially open-ended expenditures associated with those exploration and production activities. At most, the exposure of a royalty owner will be limited to its initial commitment to pay the purchase price of the royalty.
While the creation of a royalty cannot entirely extinguish the risks associated with oil and gas exploration and production for either a producer or a royalty owner, it offers a meaningful alternative to a farm-out and a means by which the risks associated with oil and gas operations can be shared and mitigated to a greater or lesser extent.