When companies sell their oil and gas assets before production has even begun, they may turn a profit long before the host country can collect the tax revenues typically associated with production. The prospect of an immediate upside for industry with uncertain or delayed benefits for countries has sparked a debate over capital gains taxes on pre-production sales. Analyst and RWI advisor Keith Myers reviews current controversies in Uganda and Ghana, using these emerging oil nations to make the case for clearer extractive sector taxation rules.
The transfer of pre-production oil and gas assets in Ghana and Uganda has triggered disputes over the fairness and taxation of capital gains. This note aims to clarify some of the issues involved and make the case for clearer rules in future petroleum agreements concerning asset transfers and capital gains taxation.
The sale of Heritage Oil's assets in Uganda and Kosmos Energy's planned sale in Ghana has sparked contention over whether, and how much, capital gains tax is due when pre-production assets are sold. Both deals deliver very high returns on investment for the companies involved, but not returns that are without precedent for companies discovering new billion-barrel petroleum provinces in frontier areas.
However, the deals are hard to explain politically because the returns to investors have been delivered before production has started and significant government tax revenues paid.
Unfortunately, there is no standard practice in oil producing countries for the treatment of capital gains and no consensus on best practice. It should be no surprise then that these deals give rise to disputes, symptomatic of immature petroleum governance systems in both countries. (Uganda has changed its tax rules three times in the last two years.)
While the moral case that Uganda and Ghana should benefit financially from the sale of their oil assets is clear, the legal arguments on either side are less so. The rules concerning the transfer of petroleum assets and capital gains taxation in both Uganda and Ghana should be clarified and included in the good governance agenda.
This note examines the situations in Uganda and Ghana and places them within the context of the three most common approaches to taxing capital gains on oil properties used by oil producing countries.
The taxation of gains on disposal of petroleum licences is central to conflicts holding up the transfer of assets in Uganda from Heritage to Tullow Oil, CNOOC and Total. Tullow has exercised pre-emption rights to acquire Heritage's interests for $1.45 billion.2 Tullow in turn proposes to sell part of its interests to CNOOC and Total. The Ugandan government claims a tax of more than $400 million (which Heritage disputes) on the Heritage disposals, and aims to claim further tax on Tullow's disposals. In Ghana it has been reported that Kosmos had negotiated to sell its interest in the Jubilee Field to ExxonMobil for more than $4 billion. This sale was abandoned in the face of objections from several parties, including the Ghana National Petroleum Company, which wants to buy the interest itself. Again, the tax treatment of any disposal may be an issue.
The sums involved are significant and the issue is highly political - $400 million is more than the Ugandan government's annual health budget. Ugandan Energy minister Hilary Onek was quoted by the Financial Times3 as saying, "The oil fields are not in London. They [Heritage] are doing business here based on a national asset. They are obliged to pay the tax." He continued, "If I were Heritage I would not go for arbitration. I would just pay my tax and get my super profit."
This brief first compares the Heritage and Kosmos transactions to assess the extent to which they could be described as abnormal or "super profits" in the context of the industry. It then describes three models for taxing capital gains used by producing countries and examines the key policy issues that arise. Lastly, it considers the tax issues arising on disposals of petroleum licences in Uganda and Ghana, using these cases to illustrate some of the policy issues highlighted in the earlier discussion.
Are the Heritage and Kosmos transactions exceptional?
Table 1 Selected oil and gas transactions for oil and gas companies.4
|Company||Country||Year||Years of operation||Equity Capital Invested||Exit Equity Value||
Table 1 shows selected corporate transactions between 2004 and 2009. Measured in terms of dollars returned for every dollar invested, the Heritage and Kosmos transactions rank in the top five with returns of $9 and $8 respectively for every $1 invested. While high, the returns have industrial precedents. It should also be remembered that when Heritage first signed its exploration agreements with Uganda in 1997 the oil price was around $19/bbl and the area was a complete frontier - considered to be very high risk and of little interest to larger companies.
A good analogy would be Cairn Energy's market valuation following its exploration success in the period 2002-2004 in Rajasthan, India. Cairn bought out Shell's interest in the frontier basin in 2002 and proceeded to make a series of discoveries reporting two billion barrels of oil in place by the end of 2004 pre-development. Cairn spent just over $300 million on exploration and the market capitalization increased by $2.7 billion: an increase of approximately $9 for every $1 invested in exploration and very similar to the returns realized by Heritage and Kosmos. Unlike Heritage and Kosmos, Cairn Energy decided to stay and develop the oil they had discovered, spending $2.5 billion through their 62%-owned listed subsidiary Cairn India. Cairn recently announced a sale of up to 80% of its equity in Cairn India to Vedanta Resources for $8.5 billion.7
The returns may seem extraordinary in retrospect, but it is rare for a small company to be instrumental in the discovery of a new billion barrel petroleum province. This is what Cairn, Kosmos and Heritage have done.
From the host country's perspective, a high sales price could be seen as a positive thing as it suggests the buyer is anticipating very significant levels of production that should lead to future taxes and royalties for years to come. Selling companies would argue that large capital gains simply indicate that they have created significant future value for the government through their activities.
The complications in Uganda and Ghana are that the transactions (or planned transaction, in the case of Ghana) were made before production (or even development, in Heritage's case) had commenced. Thus, the companies are realizing very large profits before the government has begun to receive taxes or royalties from the assets. This fact has highlighted the issue of capital gains taxation in the extractive sector in a way that a mid-stream sale of producing assets perhaps could not: it is hard for politicians to explain how large profits have been made on national assets without any taxes yet being paid.
While the timing of these particular transactions has created a particularly acute political issue, from a policy perspective the questions they raise about how to best tax capital gains are relevant in virtually all mineral rich countries. How do most countries tax capital gains?
Approaches to Capital Gains Tax
Gains on licence disposals are not normally relevant for the purposes of calculating royalty, production sharing or resource rent taxes. The issue is how they are dealt with for the purposes of corporate income tax (CIT). Broadly speaking, there are three possible approaches to taxing capital gains on the disposal of oil and gas assets:
- Ignore gains on licence disposals in taxing both seller and buyer;
- Tax gains on the seller and allow a corresponding deduction to the buyer; or
- Tax gains on the seller but restrict deductions for the buyer.
Approach 1 - Ignore Capital Gains
One approach is for gains to be disregarded in taxing both seller and purchaser. This leaves companies free to negotiate deals on a purely commercial basis, without having to adjust transaction prices to account for any capital gains tax. To take a simplified example, if company A is a willing seller and company B a willing buyer and each agrees that the value of a licence interest is $1 billion, they can do the deal at that price without tax complications. This treatment is clearly favoured by companies as it minimises transaction costs, but it also has advantages for the government as it makes it easier to transfer licences to those companies with the capital and expertise needed and best placed to develop the country's resources effectively. Moreover, it is administratively simple.
From a purely economic policy perspective, this approach also holds some attraction. As long as the government is satisfied that a reasonable share of oil revenues will be paid to it over the lifetime of licence operations, it theoretically need not concern itself with licence transfers and their impact on how benefits are shared among successive licence holders. This approach is followed by Norway and several other countries have adopted it in recent years.
While this approach may be the most convenient for the taxpayer and hold some theoretical economic advantages for countries, it is nevertheless somewhat unconventional from a tax theory viewpoint. After all, gains on the sale of licence interests are often huge, and if the purpose of CIT is to tax a company's income, how can it be right just to ignore them? Moreover, there are strong practical reasons why governments might wish to tax gains on a sale. It is clearly difficult for the government of a developing country to be seen to allow oil companies to walk away without paying tax on a billion dollar gain. The gain may arise early in the development of the country's oil resources; the public may have inflated expectations of oil benefits, and be impatient for them to be realised; or the public may mistrust the government's intentions. Theoretical arguments about long-term tax neutrality or the administrative convenience of ignoring these gains for tax are likely to be outweighed by the government's concern that they will be perceived as allowing oil companies to make a killing at the country's expense. It is more normal, therefore, for governments to seek to tax them. The issue then is whether they preserve a degree of neutrality by allowing a deduction for the buyer's cost, or tax buyer and seller asymmetrically.
Approach 2 - Tax Gains and Allow the Buyer a Corresponding Deduction
Angola is an example of a country that taxes gains but allows a corresponding deduction to the buyer. Oil tax legislation in 2005 introduced this treatment for all sales of licences, including those acquired before that date. The policy is neutral in the sense that the buyer of a licence interest gets a deduction of the same amount as is taxed on the seller, but it can produce a significant advantage to the government by bringing forward cash flow. The seller's gain is taxed immediately, but the buyer's deduction is allowed by way of depreciation allowances spread over several years. Depreciation allowances, furthermore, typically do not start running until commercial production starts, so if a licence is sold during the exploration or development stage, it can be years before the buyer enjoys any benefit from the deduction. (Note also that Angola, like many other countries, allows no deduction for signature bonuses - which are often substantial - paid on the inception of a licence.)
Let's look at how our earlier simplified transaction is affected by this treatment. Say that company A has spent $300 million on exploration and development of its licence interest but has not yet received tax relief because production has not commenced. If it sells its interest to company B for $1 billion, it will be subject to tax at, say, 50% on its $700 million gain, resulting in tax of $350 million. B inherits A's entitlement to depreciation allowances on the $300 million expenditure already incurred, and also gets a deduction for $700 million (the amount of the purchase price over and above A's historic expenditure) at 50%, corresponding to A's gain. B would have a tax deduction of $700 million + $300 million at 50% = $500 million and so would, in effect, have paid $500 million while A would receive a net $650 million after taxes for an asset they had agreed was worth $1 billion.
This clearly tilts the deal in B's favour, so it would be reasonable for the parties to adjust the sale price to achieve the same net result as if the capital gain was not taxable. If the taxation of A's gain and the deduction of B's corresponding cost took effect simultaneously, this could be achieved by increasing the sale price to $1.7 billion. (A's tax liability would now be: $1.7 billion - $0.3 billion = $1.4 billion @ 50% = $0.7 billion, leaving it with the same $1 billion net proceeds as it would have received had the gain not been chargeable. B's deductions of $1.4 billion ($1.7 billion - $300 million) @ 50% would similarly leave it with the same net cost of $1 billion.) However, this serves to increase the up-front cost of the transaction by $700 million. In effect, B would be "lending" the government $700 million, which would be repaid from future tax revenues from the asset.
It becomes even more complicated though, as B's deduction would be deferred, and taken over a set period of time after production starts. Say that, compared to the $700 million tax payable by A, the net present value (NPV) of B's $700 million future tax relief was only $550 million. In effect the government would enjoy a cash flow benefit worth $150 million (the difference between today's value of $700 million and the NPV of future tax deduction of $550 million), and A and B would suffer a cash flow loss of that amount between them, which would have to be factored into their negotiations.
While, on an NPV basis, the government gains from this treatment, there are potential disadvantages to the government as well. This approach may discourage rationalisation8 of licence interests, by increasing transaction costs as shown above and, since licence transfers are often more complex than our simple example, applying the rules may be difficult to administrate. Companies may, furthermore, seek to structure transactions so as to avoid taxation of gains and the resulting cash flow loss. These disadvantages are of course even more likely to occur where a country imposes an asymmetrical tax treatment on seller and buyer, so we'll briefly consider that kind of treatment before looking at how companies might avoid taxation of gains on licence transfers.
Approach 3 - Asymmetrical Treatment of Seller and Buyer
The UK provides a prime example of asymmetrical treatment. Capital gains in general fall within a special capital gains tax (CGT) regime. Capital costs on some classes of expenditure are deductible in calculating trading income, but other capital costs - potentially including substantial costs paid for petroleum licence interests - can be deducted, if at all, only in calculating gains within the special CGT regime. CGT losses cannot be deducted against income but only against other capital gains. Then there are restrictions on loss relief on "wasting assets" - i.e. precisely those assets (such as licence interests) on which losses are most likely to arise. The CGT regime for the UK petroleum sector is subject to further "ring-fencing" restrictions. This regime is clearly designed to make it difficult for companies to obtain relief for particular kinds of capital cost or for losses on capital transactions. It is a natural target for special pleading for exemptions and for tax avoidance, and as a result the UK CGT regime has developed into a nightmare of confusion and complexity, the details of which are beyond the scope of this note. Suffice to say that the tax consequences of licence sales in the UK can be unfavourable, but in any particular case will depend on a number of complex factors, such as the company's overall CGT position, the exact nature of the transaction and of the assets included in the transfer, and the company's ability to take advantage of various legal exemptions or loopholes.
The non-neutral treatment of petroleum licence transfers in the UK is largely a by-product of its special CGT regime rather than anything specifically aimed at the oil industry. Many other countries (e.g. the US) also have special capital gains regimes, and similar asymmetrical effects can also apply to licence transfers in those countries. The precise effects depend on the exact nature of their capital gains rules (there are few countries with rules as complex and confusing as the UK's). But it is also possible for a country with no special CGT regime to impose an asymmetrical treatment specifically on transfers of petroleum licences. This approach produces more tax, and the temptation to adopt it may be greater where the government considers its existing licence terms unsatisfactory - perhaps because they were negotiated at a time when the country's prospectivity was not fully appreciated. It may be seen as giving the government a second bite at the cherry (though of course only in cases where licences are actually transferred).
Companies will often regard such asymmetrical regimes as effectively imposing double taxation. The sale value of the licence interest is the NPV of the post-tax revenues it will generate, and by taxing that value without giving relief to the buyer the government is effectively taking a further tax slice from those revenues. This slice may be very large. Taking our previous example further, if company A has to pay a tax of $350 million on its $700 million gain, but company B receives no corresponding deduction, company A will be $350 million worse off. In order to share the pain between them, the $1 billion sale price will have to be adjusted upwards - which will unfortunately increase the pain as well as share it!
Structuring Transactions to Avoid Capital Gains Tax
There is an important practical consideration that countries must keep in mind. No matter how strong the political will to tax capital gains may be, multinational companies may seek to avoid the pain of capital gains taxes in various ways. One approach is, instead of company A selling its licence interest to company B, for company A's foreign parent to sell some or all of its shareholding in company A to company B's foreign parent. (There may also be non-tax reasons for doing this.) Of course there may be all sorts of reasons why structuring a transaction in this way is difficult or unsatisfactory, but where it is possible, the transaction would fall outside the taxing legislation in many countries. Even if a country designed legislation to tax such transactions, it would likely be difficult to apply in practice and could very well be overridden by double taxation agreements. One solution is to make the purchaser liable for the seller's capital gains tax, enabling the tax liability to be settled at the closure of the transaction.
Licences may be sold for non-cash consideration, for example in return for the buyer carrying out a work obligation (sometimes known as a farm-out, although that term is often used for any partial disposal of a licence interest) or by a licence swap. There may be non-tax reasons for structuring deals in this way, but tax planning may also be a factor. Theoretically, any gain should be taxed on the basis of the cash value of the non-cash consideration. However, it may be unclear whether the legislation allows that, and even if it does, the difficulty of valuing the consideration may persuade the tax authority to accept a no gain/no loss treatment for the sake of administrative simplicity. (The UK in fact introduced a legal exemption from CGT on swaps or farm-outs of undeveloped fields for exactly this reason.)
A factor that may be relevant is the stabilisation clause in petroleum agreements in many countries, particularly developing ones. Sometimes these "freeze" the law in force when the licence is signed, and commonly they guarantee to make good the oil company's economic position if it is adversely affected by later changes in the law. Stabilisation clauses may limit a country's ability to introduce taxation of licence sales unfavorable to investors. Uganda and Ghana have such clauses in their agreements; Angola does not (although it is still possible that companies with agreements in place before 2005 might object to the later imposition of tax on their sale).
Whether or not a stabilisation clause applies, it must be remembered that companies normally have to obtain government consent to assign licence interests. If a company is keen to sell, the practical reality may be that it has to negotiate a deal under which it pays tax in order to win the government's consent, even though in theory it is ruled out by a stabilisation clause.
Tax Treatment of Licence Disposals in Uganda and Ghana
Capital gains are taxable under Ugandan tax law and legislation to that effect was in place when the original production sharing agreements (PSAs) were first signed. There have been two previous transactions in Uganda involving the transfer of oil and gas assets. In 2004 Tullow acquired Energy Africa for $500 million; in 2006 Tullow acquired Hardman, its partner in Uganda, for $1.1 billion in a cash and share deal. Although in both deals Ugandan assets (and assets in other parts of the world) were transferred, we understand that no capital gains tax was levied at that time.
Under Uganda's legislation it could be argued that a gain can be taxed even if it is the company that is sold rather than the licence. However, this argument isn't straightforward, and neither is collecting the tax, unless there is a provision making the successor licencee liable for any unpaid tax. So the failure to collect capital gains tax on the 2004 and 2006 transactions perhaps suggests that the Ugandans didn't pick up on the possibility of taxing the gain, or thought it wasn't worth pursuing at the time of the Energy Africa and Hardman sales, which predated the biggest discoveries of Ugandan oil.
The treatment of the prior transactions should not bind Uganda in the present case, however. It is doubtful that any country would accept that failure to tax one transaction sets a binding precedent, despite existing laws that allow for such transactions to be taxed.
In 2008 the government enacted legislation under which gains on petroleum licences were disregarded for both buyer and seller (the first approach described above). The theoretical advantages of this simple system no doubt paled when Tullow and Heritage started talking about selling licence interests for huge sums, and in September 2009 the government amended the law to tax gains but give buyers no deduction (the third approach). So when Heritage announced a sale to ENI in November 2009, it would have been taxable. Perhaps under the pressure of negotiations, the government now has a draft bill before parliament which gives the buyer a corresponding deduction (the second approach) - in effect following the Angolan CGT regime.
So Uganda has followed the whole gamut of CGT regimes and has changed the rules three times in two years. Heritage says it has had legal advice that the gain is not taxable, and is taking the issue to international arbitration; no doubt the Ugandan government has had legal advice to the contrary. The argument is likely to center on which provisions of Uganda's shifting CGT regime are relevant, how they should be interpreted and how they are affected by the stabilisation clause in the PSA. Unfortunately we are not in a position to predict the outcome as we are not privy to Heritage's legal argument. However, it does seem that there is at least a case to argue that CGT would apply given the timing of the deal relative to the legislative changes.
Ghana is also an interesting case. Its legislation appears to disregard gains in taxing a buyer and seller on the transfer of a licence after commencement of production (the first approach), but a technical case can be made that on a transfer before commencement of production, it does not tax the seller on a gain but gives the buyer a deduction for the full cost! This anomaly (which lacks any coherent rationale and falls outside the three approaches to capital gains taxation described herein) seems likely to be corrected before any disposal is permitted, and it will be interesting to see what regime eventually emerges. The government will be under the same pressure as Uganda to show some return from any major disposal, but again stabilisation clauses may come into play.
The capital gains made on the sale of the Heritage and Kosmos assets are high (or expected to be high in the case of a future Kosmos transaction) but not without precedent as there are previous transactions involving companies discovering new petroleum provinces in frontier areas that have shown comparable returns. There is no standard treatment for capital gains on oil and gas assets. This fact, together with the shifting nature of Uganda's tax legislation, will make arbitration challenging and the outcome hard to predict. The rules on the transfer of petroleum assets and capital gains taxation need to be clarified and included in the good governance agenda, particularly in emerging oil and gas producing countries.
Oil and gas exploration capital is increasingly deployed in a chain, from risk-tolerant small frontier exploration companies who sell out on success to larger, capital-rich development companies who may in turn sell to larger companies wanting cash generating producing assets. The key task for policymakers is to ensure the country's natural resources are developed as efficiently as possible by operating companies with the right capabilities, maximizing value for the country over the long term. While the state must clearly have the right to approve changes of licencees, policies that discourage asset transfers between companies are misguided, discourage investment and ultimately destroy value.
Governments should be mindful of the potential value created in success scenarios when it awards licences and must ensure the fiscal regime divides the value fairly and transparently between the state and the providers of risk capital. The decision on whether the state wishes to have the option of pre-production tax revenue through taxing capital gains on the sale of pre-production assets should be taken in this context and ideally before licences are awarded. This would provide greater certainty for investors and may also serve to weaken the arguments justifying controversial economic stabilisation clauses in contracts.
Acknowledgements and Disclaimer
Thanks to Richmond Energy Partners Limited for permission to publish this paper and to my tax accountant colleague who helped with the intricacies of tax law. This report does not constitute an offer to buy or sell any securities, nor does it constitute advice in relation to the buying or selling of investments, nor does it constitute a recommendation to purchase or sell securities, nor does it constitute legal or tax advice. This report does not provide a comprehensive analysis of the financial, legal and tax position, assets and liabilities, profits or losses and prospects of the company or entity that is the subject of the report and nothing in this report should be taken as comment or implication regarding the relative value of the securities of any company or entity. This report is based on the author's experience, knowledge and databases as well as publicly available sources. The author does not guarantee the accuracy of this data. The opinions expressed in this report have been arrived at after careful consideration and enquiry but we do not guarantee their fairness, completeness or accuracy. The opinions expressed are subject to change and the author does not accept liability for any reliance on them.
1 Dr. Keith Myers is an oil and gas industry analyst and former oil company negotiator based in London, UK. Keith is managing partner of independent research company Richmond Energy Partners Limited. He also served on the organising committee of the Chatham House Good Governance of the National Petroleum Sector project. He acts as an adviser to Revenue Watch on oil sector governance issues and has provided oil and gas governance training for parliamentarians in both Uganda and Ghana.
2 Tullow Oil press release 27th July 2010
3 FT.com, June 17th 2010
4 Source: Company reports and Richmond Energy Partners Limited analysis
5 Recycle ratio is defined here as the number of dollars returned for every dollar invested.
6 Kosmos transaction parameters are estimates only. The transaction was cancelled on the 8th August 2010.
7 Cairn Energy Press Release, 16th August 2010
8 "Rationalization," in this context, is used to mean the matching of mineral deposits--through the purchase and sale of licence interests--with the companies best able to develop them and thus most likely to provide the best returns to the government.