Despite its seeming fiscal steadiness, the U.K. oil and gas tax regime has witnessed a number of changes throughout its development, especially during the last few years. The change that has had the most impact on the industry was the 10% corporate tax increase introduced in 2002. It came as a surprise to the industry, as it was believed that stable, low oil prices in the late 1990s had removed the threat of increased taxes. The Treasury argued that the changes were brought in to ensure that companies paid their fair share of taxes as well as to encourage "long-term investment" in the sector. Foreign investors in particular have been put off by this change, as they believe the U.K. in general is a good but expensive place to do business, making it an even larger investment for them. Investors need stability when committing money to long-term investments. However, even after the initial changes, new ones have occurred about once every nine to 10 years. Although there may be no more giant fields to be found in the North Sea, one would expect many development projects to last for more than 10 years, and the tax regime at the end of a project life can still have a strong influence over the project's economics. Having said this, despite the 10% corporate tax increase, marginal tax rates for new oil and gas fields remain at 40%, and are still some of the lowest in the world. Overall, these measures have been revenue-raising for the government and driven by political factors, but there have also been beneficial developments. According to U.K. Energy Minister Stephen Timms, the government has been focusing on providing incentives to specific areas of the industry that have been perceived as weak. These include: • Changes to the capital allowances regime giving 100% first-year allowances for the majority of U.K. upstream capital expenditure. • Abolition of royalty from January 2003. • PRT exemption for tariff income arising from new business from January 2004, in order to promote further use of existing North Sea infrastructure. To anticipate future changes in the tax regime one needs to take into account the declining North Sea reserves and reduced exploration. The larger operating companies are focusing their activities in Africa and Russia while smaller players are coming into the market to develop mature assets. The government's strategy to extend the life of the North Sea and maximize recovery is intended to encourage exploration and to further the use of infrastructure. The Fallow Fields Initiative is intended to persuade the majors to divest their portfolio of assets that do not fit their strategic review, but this has been a very slow-moving process. While some smaller developers have been successful working on certain mature assets, some of the larger operators have yet to divest other assets that have not seen any development for years. In 2004 the government will need to have a good strategy in place as to how it will be able to encourage brown-field development where only larger independents or the majors will be able to play a leading role. This will very probably be a point of friction between the industry and the government. Investors from the U.S. and elsewhere looking to invest in North Sea projects will be concerned as to what the tax regime is likely to be for the whole of their expected investment period. Given past changes, it is unlikely investors will ever feel comfortable that there will not be further major changes to the regime in the future. Abandonment issues The abandonment issue is one of real concern as some of the sector's major fields near the end of their economic life. To date, only a number of small fields have been abandoned and most of these have used floating production facilities or have been linked by a subsea tie-back to another field. Where existing infrastructure has been removed, the facilities have been on Southern Basin gas fields. The facilities have been removed by a simple crane lift operation. Historically, tax relief for abandonment expenditure was available as a normal disposal of plant and machinery or under the abandonment allowance regime, which gave a 100% immediate deduction for the costs of demolition of plants and machinery for the purpose of closing an oil and gas field. The Inland Revenue's interpretation of this legislation was strict, and the cost of "mothballing" assets for possible future use or of preparing an asset for reuse was not allowed. One consequence was that the assets could be more economic to sell than preserving or attempting to reuse them. To address this, in 2001 the 100% immediate deduction was extended to all expenditure incurred in decommissioning a field provided: • Expenditure incurred on decommissioning (explicitly defined to include mothballing and reuse costs) U.K. offshore infrastructure; • Decommissioning complies with an approved abandonment program; and • Plants and machinery are not to be replaced. Where a company has discontinued its ring-fence activities (that is, has ceased oil and gas production) and incurs abandonment costs within three years of the cessation, the company can claim a 100% capital allowance for the spending in its final trading period. While this enables businesses to receive a 100% balancing allowance for the final period of the company's trading period, the three-year time limit may be inadequate to guarantee effective relief, particularly if the field has a common transport or terminal facility, in which case full abandonment cannot proceed until the last-user field ceases production. Where a participator in a field meets another participant's abandonment costs under the term of an abandonment guarantee, that expenditure will generally qualify for relief as though the original participator had incurred it. Where the company has ceased to trade, losses resulting from abandonment can be set off against profits of the trade in the preceding three years. Many in the industry have concerns that this period is inadequate, particularly as fields tend to be less profitable toward the end of their life and thus the losses available for carry-back can outweigh the profits available to be relief. Access to infrastructure The investment required to build the infrastructure needed to transport oil and gas from offshore fields is characterized by significant costs and irreversibility. This can lead to conflict between the efficient use of resources and the wish for greater competition. The efficient use of resources requires no unnecessary duplication of infrastructure while greater competition requires alternative pipeline systems to be available to producers. Effective regulatory action can prevent the exploitation of local monopoly positions where competing pipelines do not exist. The evolution of offshore infrastructure on the U.K. Continental Shelf (UKCS) has been characterized by companies developing pipelines for their sole use, followed by spare capacity progressively being made available for use by third parties on payment of a tariff. Field-dedicated lines are economically viable when fields are relatively large but become less viable as fields get smaller. There is scope for gains for all parties if the development of small fields is made viable by the owners allowing access to their existing infrastructure, thus gaining additional revenue from the new users. Some of these gains would be lost if monopolistic behavior were to deter the development of new small fields. The more mature areas of the southern North Sea, with large amounts of part-empty infrastructure, offer good opportunities for pipe-on-pipe competition. In the central North Sea, there is less spare capacity and the additional complication of relatively small gas volumes associated with oil production. There is more potential for commercial tension between the owners of infrastructure and the owners of third-party fields seeking access to that infrastructure. The scope for tension between non-proliferation of infrastructure offshore and competition creates a need for regulation. The Secretary of State has the power, under the Petroleum Act 1998, to impose a solution to problems involving pipeline-sizing, connections or tariffs. These powers have, however, so far never been exercised. Changing dynamics For many the recent tax increase contributed to a change in strategy, with larger operating companies starting to scale back their North Sea operations to focus on other regions. In response, the government and the industry are working on initiatives to prolong the life of the North Sea, notably by encouraging exploration and further use of infrastructure. Insiders expect that the recent changes to North Sea taxation may not be the last, with future policy being driven by three potentially contradictory factors: • The government's formal policy of being "guided not by short-term factors but by the need for a regime that raises a fair share of revenue and promotes long-term investment in the North Sea;" • Declining revenues which may see the gradual withdrawal of major global players and their replacement by smaller, leaner but less-capitalized businesses unable to maintain the existing level of North Sea infrastructure; • The U.K.'s economic position, and that of the global energy markets. In 2004, the North Sea oil and gas sector remains a vibrant but evolving sector, which remains critical to the U.K.'s economic and taxation policies. As the North Sea oil and gas fields move into the later stages of their lives, tax changes remain likely.