Chapter 4: Into the new millenium

“Oil/NGL (natural gas liquids) production is continuing to set record levels, aided by substantial upgrades on existing producing fields. These upgrades have allowed almost all the participants in the Norwegian sector to realize significant additions to their commercial reserves base.” It was not long before newspapers were dusting off the old clichés about Norway being the Kuwait of Europe, while their cartoonists portrayed the Norwegian finance minister as bathing in money.

The Norwegian Ministry of Petroleum and Energy, normally conservative in its projections, was predicting that innovative projects would keep Norwegian oil production vigorous for much longer than previously believed. Far from stabilizing at three million barrels per day, crude output would probably rise to about 3.7 million barrels per day by the turn of the century and then taper off more slowly than previously expected. Nor was production as high as 4.4 million barrels per day ruled out  a development that would have boosted Norway’s rank as the world’s sixth largest oil producer to fourth place, behind only the United States, Saudi Arabia and Russia.

Near boiling point
There were, inevitably, calls for a slowdown in oil production in order to prevent a national overdependence on petroleum income. Economists warned that the Norwegian economy was near the boiling point: a record level of exploration and construction activity and a queue of new development proposals (stimulated partly by the success of NORSOK) were stretching offshore contractors beyond capacity and raising the dreaded spectre of inflation.

Economic depression in Asia cut deeply into oil demand at just as long-term overproduction by OPEC countries had begun to swell inventories worldwide. The result was that the price of North Sea crude plunged to Chapter 4: Into the new millenium1 four months later  a shock to the government and high-flying offshore companies alike. From a later vantage point, this last development would seem to have taken place on another planet.

With an enviable state budget surplus, Norway was sure it could handle any short-term price shock with aplomb. But analysts looking into the future saw no immediate reason for prices to rise back above Chapter 4: Into the new millenium5 per barrel  perhaps ever. Little did they know! Meanwhile, the financial carnage continued. International currency speculators who knew nothing about the Norwegian economy except that it was oil dependent began to sell kroner in large quantities, with the result that domestic interest rates soared to the highest level in Europe. Norway was not alone in its suffering: every nation for which oil production was more important than oil consumption had a headache.

Analysts at Wood Mackenzie saw choppy financial waters as natural for a technological pioneer. “The upstream industry in Norway has been developing and utilizing cutting-edge technology in many of its field developments, which, although encouraging for the continued advancement of the industry as a whole, could be viewed as having come at a high price for several of the projects”, the company reported.

In many respects, moreover, long-term confidence in Norway never faltered. Almost every Norwegian field remained profitable at Chapter 4: Into the new millenium0 per barrel while some could make money down to as a little as $4 per barrel. In the competition for international capital, analysts said, the Norwegian continental shelf would hold its own against upstart oil provinces with lower wages even if the slump lasted several years.

The Norwegian state itself was the biggest North Sea oil investor, and its budget was projected to remain comfortably in surplus for many years. In the private sector, the merger fever that sent British Petroleum into the arms of Amoco, Exxon to Mobil and Total to PetroFina did not initially penetrate to the Scandinavian market. Statoil, the state-owned company run largely as a private enterprise, bought 20 per cent of the shares in Saga Petroleum in 1998; but when the purchase was interpreted as a trial balloon for takeover, the idea was shot down by authorities who urged all parties to display “ice in their bellies” until better times returned.

	Economic depression cut deeply into oil demand and the price of North Sea crude plunged....

Upping the ante
However, in 1999, 44 per cent state-owned and Oslo-listed Norsk Hydro upped the ante, launching a hostile takeover bid for Saga Petroleum. When upstart French rival Elf Aquitaine put in a higher bid of its own, Norsk Hydro initially dug its heels in. Eventually, with the assistance of Statoil (which got to carve some of Saga Petroleum’s juicy assets out for itself), Norsk Hydro bid an even higher price, and triumphed.

The antics attending the demise of Saga were criticized  in some respects rightly so  as an example of Norwegian isolationism. But this “Norwegian” logic was compelling as well. The government had conceded on numerous occasions that in an increasingly consolidation-conscious world, three Norwegian oil firms might be one too many. If mergers and takeovers were not to be pursued, cooperation among Norwegian producers and suppliers was. In Norwegian eyes, the situation surrounding Saga Petroleum was that simple. To regain the cost-cutting edge that had done so much to boost confidence, industry movers set up NORSOK II. They also reinvigorated a separate industry forum called FORCE to stimulate additional new technologies for increasing oil recovery rates  already the highest in the world  and to heighten return on investment.

Cutbacks, coalitions and cartels
Meanwhile, exploration cutbacks were seen as natural: 20 per cent at Statoil and 50 per cent at Norsk Hydro, for example , to which the Norwegian companies responded by agreeing to share seismic data, while Phillips Petroleum announced a reduction in its workforce of 570 people... although this was partly the result of increased automation in its rejuvenated Ekofisk field.

“We’ve adopted extensive measures to respond to a development characterized by lower prices and profit margins for our products”, said Harald Norvik, Statoil’s then CEO. “Investment will be cut and new projects must be profitable at a lower oil price. “At the same time, we’re continuing and strengthening a number of measures to reduce operating costs, and reorganizing our administrative work processes to make more effective use of personnel. These efforts will help to make us more robust.”

	Analysts said the Norwegian continental shelf would hold its own against upstarts.

In Norway the state energy ministry  which oil executives recognized as a stable and benevolent force compared with energy authorities in many parts of the world  was eager to help. Its unusual step of joining with OPEC and Mexico on production cuts caught the attention of the New York Times, not so much because of Norway’s 100,000 barrel per day contribution, but because of what the newspaper saw as “an emerging coalition of oil exporting countries”.

The spectre of a broadened oil cartel receded as 1998 progressed, but it was food for thought now that animosities from the 1970s had largely died away and diverse oil producing lands realized they had much in common. The former general director and chairman of Norsk Hydro, Torvild Aakvaag, urged Norway to form cooperative ties to OPEC and other oil producing countries, but it was unclear how that would sit with Norway’s friends in the consuming West.

While oil prices proved unleverageable in the late nineties, the government took firm action to break up the logjam of field development projects that had stretched contractor capacity and contributed to the cost problem. The plan, to delay government approval for a dozen projects by one year, was generally supported by the industry. Left to their own devices, the developers probably would have put most of the projects on ice anyway, especially in marginal real estate like Amerada Hess’s Freja field, where the oil rests 5000 metres below the seabed.

Despite some carping about the government’s high profile, international investors showed no sign of bolting the North Sea. Shortly before merging with BP, Amoco made an impressive hydrocarbon strike in the Donnatello structure south of the Norne field. Interest was heightened again when 33 new blocks or partial blocks were opened to licence bidding, albeit largely in well-known areas whose resources could be tied back to existing production facilities.

Heating up
The country’s long-term strategy of draining small and difficult reservoirs as well as the big, easy ones remained intact  a sign of confidence that operators had the technological and administrative wherewithal to continue making it work economically. To most observers, it appeared that the Norwegian petroleum industry and its many partners from abroad would emerge fitter than ever from their fin-de-siècle trial.

Towards the turn of the century, matters began to heat up at Statoil, Norway’s 100 per cent state-owned oil behemoth. Basically, Statoil realized it was not a stock exchange listed company like its foreign rivals, and began demanding that its indifferent parent buy it the best birthday present of all: a foreign (equity) partner to play with.

The move sowed the seeds of a total, head-to-foot overhaul of Norway’s oil economy, the ramifications of which would reverberate well into the new millennium. Statoil boss Harald Norvik set the ball rolling in the spring of 1999 with a blunt statement that the state ownership model was outdated for our day and age. He demanded privatization.

Mr Norvik, along with his entire board, was then sacked by the government after copping the blame for the Åsgard cost overrun; but his crusade was taken up by his successors. In the autumn of 1999, chairman Ole Lund put forward a formal board proposal to privatize and list Statoil on the Oslo Stock Exchange, after first combining it with all or most of the Norwegian state’s direct financial interest (SDFI) in petroleum assets. The SDFI, formed in 1985 to dilute Statoil’s dominance, is far larger than Statoil itself, holding about 40 per cent of the state’s upstream wealth.

At this stage, Norway’s slow march towards privatization and internationalization involved the preparation of a government White Paper and a parliamentary debate on the privatization of Statoil, the future of SDFI, reorganization of petroleum taxes and the role of foreign majors in a future offshore industry. The Statoil board stood by its original demand until, with suitable fanfare, Statoil shares finally began trading on the Oslo and New York stock exchanges in June 2001. The state initially offloaded about a fifth of the oil company’s shares; the long-term plan was to retain about a two-thirds stake, which would enable the government to overrule strategic decisions deemed not in the national interest.

Then there was the sale of the SDFI, the state’s direct financial interest, established in 1985 because it was felt that Statoil was getting too big for its own good. Both Statoil and Norsk Hydro were clamouring for shares. In May 2001 the government started the sell-off of 21.5 per cent of the SDFI. Statoil acquired 15 per cent for NOK 38.6 billion; Norsk Hydro and other foreign companies queued up for the rest.

A tale of two cities
Following the national election of September 2001, Einar Steensnæs was appointed minister of oil and energy. He was known to be especially keen on doing business with London and Washington, the two capitals, apart from Oslo, that matter most in the offshore sector. In London he spoke of the need to foster links with Britain, especially as that country was gradually becoming a gas importer. But he also outlined his vision for Norway itself, involving two major goals: improvement in the recovery rate through  the use of new technology, and stronger protection of the environment.

To his audience in Washington, Mr Steensnæs said: “When you look to Norway and how we have organized our energy activities, you will find differences with the US and also that we have a lot in common. I see a promising future for the oil and gas sector in Norway. A future we invite you all to participate in.”

Mr Steensnæs soon faced the first test of his resolve. Norsk Hydro had expressed its dissatisfaction with the size of Statoil’s share of the SDFI, and the fact that only 6.5 per cent was left for all other bidders. Others in the Norwegian oil industry, meanwhile, were exhorting the national authorities to allot a large share of the remaining assets to foreign companies, for the sake of balance and in order to add value on the Norwegian continental shelf.

The list of foreign aspirants read like a virtual Who’s Who of the offshore world: AEDC, Agip, Amerada Hess, BP, Chevron, Conoco, DNO, Dong, EDC, Enterprise, ExxonMobil, Fortum, Gaz de France, Idemitsu, Marathon, Moeco, Norsk Hydro, Offshore Engineering Resources, Paladin, Pelican, Phillips, Ranger, Ruhrgas, RWEDEA, Shell, Svenska and TotalFinaElf.

Each company was asked to specify which assets it would be interested in acquiring. UBS Warburg and DnB Markets were appointed as financial advisers on the sale. The government had to decide whether to cede a lion’s share of the 6.5 per cent to Norsk Hydro, or whether foreign companies would be given equal consideration.

In late March 2002, the sale of the remaining 6.5 per cent of the SDFI was completed and a total of 30 licences were sold. The buyers were Norsk Hydro, TotalFinaElf, Shell, Conoco, Marathon Oil, Paladin Resources, Gaz de France, Idemitsu and DONG, Danish Oil and Natural Gas. Mr Steensnæs said: “I am happy with the results we have achieved in this process. The interest from the potential bidders has been good and we have achieved satisfactory prices for the interests sold. The restructuring of the State’s ownership interests on the Norwegian continental shelf will contribute to the creation of additional value from our petroleum activities in line with the objectives set by the Parliament for the sale. The State will retain substantial direct ownership in fields following this sale. It is important that the State, in managing the petroleum resources on the NCS, continues to act with a long-term perspective.”

Petoro and Gassco
The listing of Statoil and the sale of 21.5 per cent of the SDFI formed only one component of the restructuring of the Norwegian offshore sector. The other important component was the formation of two new enterprises, Petoro and Gassco. Petoro AS is the state-owned management company of the State’s Direct Financial Interest (SDFI) on the Norwegian continental shelf. This is the largest Norwegian offshore portfolio of oil and gas reserves, even after the Statoil-Hydro merger, and represents more than a third of Norway’s total petroleum reserves. In common with other partners in the joint ventures, Petoro is not an operator; rather, its main objective is to maximize the economic value of the SDFI portfolio for its owner, the Norwegian government.

The company reports that net cash flow from the SDFI to the government totalled NOK 57.1 billion for the first half of 2009, a clear decline from the record figure in the same period of 2008 but on a par with January-June 2007. The first half was otherwise characterized by a high level of exploration activity and “finding success in licences where Petoro has interests”. Investment also remained high as a result of commitments made in the autumn of 2008. Petoro president and CEO Kjell Pedersen said he was satisfied with results for the first half: “We’ve managed to maintain good earnings from the portfolio and exploration results so far this year are encouraging. It’s important that we not only explore in new areas but also mature new investment projects which can help to maintain production, the revenue stream and expertise on the NCS.” However, he warned that exploration and project activity might not stay at a corresponding level through 2010.

In general, lower prices, weaker results, greater pressure on liquidity and the need by the oil companies to secure financial flexibility are reflected on the NCS in a desire to postpone profitable projects. In such conditions, Petoro says it is “particularly concerned to distinguish between postponements which aim to reduce costs and ensure quality, and those primarily intended to safeguard the financial flexibility of companies and the prioritization of activities within and outside Norway”. One major aim is “to avoid a weakening of the SDFI portfolio through adjustments which might be rational for other companies”.

Long-term management
Parallel to the formation of Petoro, the establishment of Gassco created a 100 per cent state-owned enterprise charged with managing Norway’s 7800 km pipeline and gas transport infrastructure. This was especially significant in view of the anticipated longevity of Norway’s gas industry as opposed to its oil sector, given that oil in theory could run out within 30 years while Norway looked certain to remain a viable gas supplier for much of this century at least.

	A central goal is to run Norway’s integrated gas transport system with the highest possible regularity: Ormen Lange

In 2008 Gassco transported 94.6 billion scm of Norwegian gas to European terminals, an increase of about nine billion scm from the 2007 gas year. An additional 1.9 billion scm were delivered for injection into fields on the NCS, while 1.1 billion scm were supplied for domestic consumption. Increases from Ormen Lange and from the Statfjord area via the Tampen Link transport system boosted total deliveries. A central goal for Gassco is to run Norway’s integrated gas transport system with the highest possible regularity. Through extensive blending of flows, Gassco delivered 100 per cent of the gas volumes to the agreed quality in 2008.When part of the transport system dropped out, gas was lifted from other fields/terminals and guided into the system. This meant that total delivery availability came to 99.78 per cent.

Compliance concerns
The European Economic Area (EEA), of which Norway is a part even if it does not belong to the European Union, has at times viewed Norway’s leading position in the European gas market with concern, and the government has occasionally had to work hard to address worries about its compliance with EU policies. A big bone of contention was removed with the abolition in 2002 of the Gas Negotiating Committee (GFU). The infamous system of “government compulsion” had meant that individual companies were not free to sell their own gas. Brussels viewed this as illegal price cooperation, and finally got the GFU abolished. Gassco is central to the system that replaced it. The company does not own any pipelines, nor does it participate in gas sales and production: the aim is to offer regulated and nondiscriminatory access to all shippers.

Commercial players in the Norwegian market, meanwhile, have stepped up an already aggressive drive to increase the country’s presence in European gas markets  the UK, for example, which has developed its part of the North Sea much faster than Norway, whose small population and conservative attitude to the domestic use of gas have enabled it to husband its resources. Long before the European gas panic of 2006, Statoil had reckoned that British domestic demand in particular would surge as supplies began to dwindle.

Towards the end of 2003 Norway signed an historic agreement with the UK for regulating a wide range of potential cross-boundary oil and gas projects, including pipelines such as the “Britpipe” link from the Ormen Lange field to Easington and the Vesterled pipeline, which links Norway’s Heimdal gas processing facility to the Frigg pipeline, allowing Norwegian gas to flow to St Fergus in Scotland.

Tax revamp
Another aspect of Norway’s oil and gas overhaul was the revamping of the tax regime in 2001. The government’s aim was to adjust Norwegian oil and gas framework conditions to attract the most qualified companies.

The main elements of the amendments to the petroleum tax system were as follows.

• Financial costs were to be allocated based on reduced tax values, and not on income. This prevented financial costs attributable to activities outside of the Norwegian continental shelf from being deducted against the petroleum tax bases. This rule would reduce incentives for tax motivated investment, establishment or acquisition on the mainland or abroad.
• Deficits in petroleum income would now be carried forward increased by interest both for the corporate tax and the special tax. The aim was to equalize the cost of capital expenditure for new entrants with those for existing players on the Norwegian continental shelf, and so encourage the participation of new entrants on the NCS.
• Losses in case of a disposal of business activities or a merger of companies could now be transferred to companies acquiring the business. Some companies might never reach a tax level making it possible to exercise all their tax-deductible losses; the ability to transfer such losses would certainly reduce the financial risk to new entrants trying to establish themselves on the Norwegian continental shelf.

	Bird’s eye view of Statoil’s Kollsnes natural gas processing plant west of Bergen. Kollsnes treats gas from the Troll, Kvitebjørn and Visund fields and can handle up to 143 million standard cubic metres per day.

Licensing rounds
The seabed off the Norwegian coast still hides significant volumes of oil and gas, and many companies want in on the feast. The production licence is their admission ticket.

To begin with, the continental shelf is divided into blocks, which represent geographical areas defined by specific geographical coordinates. The block concept is important in the petroleum activities, because a production licence normally comprises part of a block, an entire block, or multiple blocks, and is granted to one or more companies.

Production licences are awarded in ordinary licensing rounds (usually every other year) and Awards in Predefined Areas, so-called APA awards (every year). A total of 20 offshore licensing rounds have been implemented on the NCS since 1965. The numbered rounds are characterized by offering unexplored acreage to the industry. North Sea rounds were introduced in 1999 in order to enhance exploration activity in the mature parts of this area, and three were held until they were replaced by the APA system, which covers mature acreage in all parts of the NCS, and not just the North Sea. An ordinary licensing round starts when the Ministry of Petroleum and Energy invites the oil companies to nominate blocks which they believe should be included in the announcement. After a thorough review, the ministry  with input from the NPD  prepares a list of blocks that the agencies want to include in the licensing round. After consultation and negotiations with parties including the fishery and environmental authorities, the ministry announces the blocks for which the companies can apply for production licences, including any special environmental and/or fishery conditions that apply to such blocks. Companies can apply individually, or as part of a group.

Based on the applications received, the government awards production licences. If several companies have applied together (as a group), the composition of the group, recommended operator and joint competence will be assessed. Companies that apply individually may be added to a group; alternatively, several companies that apply individually may be awarded ownership interests in the same licence. When awarding licences, the authorities consider technical expertise, understanding of geology, financial strength and experience (from the Norwegian shelf or other locations, other activities, etc.) of the applicants.

Terms and conditions
The production licence governs the companies’ rights and obligations vis-à-vis the Norwegian State. The document supplements the requirements in the Petroleum Act and sets out detailed terms and conditions for each individual licence. The production licence is an exclusive right to carry out surveys, exploration drilling and production of oil and gas within the defined geographical area. Each individual licensee owns its share of the petroleum produced.

As a rule, the production licence is valid for a so-called initial period (exploration period) of four to six years. The licensees can apply to extend this period to up to ten years. During this time, a specific work commitment must be completed in the form of e.g. seismic data acquisition and surveys and/or exploration drilling. When the initial period is over and the work commitment is completed, the licensees can apply for extension for a period as stipulated in the production licence. In general, this period is up to 30 years.

If exploration drilling does not prove oil or gas, the main rule is that the area shall be relinquished at the end of the initial period. For production licences awarded before 2004, the main rule is that the licensees in the production licence can demand to retain up to one half of the area of the production licence for up to 30 years (if the work commitment is completed during the exploration period).

In connection with the 20th licensing round on the Norwegian shelf (2008), a new scheme was introduced involving a broad-based public consultation regarding proposed blocks. The aim was to promote more transparency so that various stakeholders among the general public could voice their opinions before the Ministry made its decisions, and to ensure critical examination of the social as well as technical consequences of the proposal.

Some notable licensing rounds
The 17th licensing round on the Norwegian continental shelf was another favourable omen for future internationalization of Norway’s oil sector. This was the first licensing round where oil companies were allowed to form groups. Fresh off its stock exchange listing, Statoil went in partnership with Royal Dutch/Shell and Enterprise in this round. BP and Conoco tied up, while ExxonMobil and Norsk Hydro combined for certain specific sections.

This round was also special because it offered opportunities in deepwater acreage in the Norwegian Sea off the middle of the mainland, where there is potential for natural gas. This neatly complemented Statoil’s overrepresentation in the declining North Sea abutting the southwest of the country, where it mainly produces oil.

The government described the round as an important step in the further exploration of the Norwegian Sea as a petroleum province. “Through this licensing round”, then minister Einar Steensnæs said, “we will open up for new activity and future income. At the same time, the relationship between the petroleum activities and other important society interests is important. I would like to emphasize that we are seeking a balance between the interests of the environment, the fisheries, the fish farming industry and the petroleum activities, within the framework of sustainable development.”

The 18th licensing round for 2004 upped the stakes  and the pace  dramatically. It included 95 blocks or parts of blocks, almost three times the number included in the previous round, and in Mr Steensnæs’ words was expected to lead to “increased and efficient exploration of frontier areas of the shelf”. The large number of announced blocks underlined “the need for rapid and efficient exploration and development of possible resources in the awarded areas”. In terms of acreage, this was the largest conventional announcement on the Norwegian continental shelf since the first licensing round in 1965.

Way up north
In the 19th licensing round in 2005, the main focus was on the Barents Sea. Describing the awards as “an important step on the way to long-term exploration in this area”, the oil and energy ministry said: “With the awards in the 19th licensing round and the work with the integrated management plan, the Barents Sea has been given new opportunities.”

The announcement of the 19th licensing round in 2006 also focused on areas in the Barents Sea, and the western part of the Norwegian Sea, representing an important step towards exploring these areas. Announcement of the 20th licensing round, scheduled in 2007, was postponed until 2008 with award of production licenses in 2009. The postponement, it was felt, would allow use of the results from a number of ongoing exploration wells in the formulation of the next round. The risk of drilling dry wells would be reduced, and the principle of gradual, cost-effective exploration activity safeguarded.

Announcing the awards of 21 new production licenses in the 20th Licensing Round in May 2009, the minister described it as “an important contribution to new industrial activity and jobs at a time when Norway is in the middle of a serious economic situation” and “part of the effort to increase petroleum activities in the northern areas of Norway”. The awards, he continued, would “contribute to a steady level of activity on the Norwegian Continental Shelf and counteract future production decline, thereby maintaining the important role of Norway as a reliable and predictable supplier of energy”.

New frontiers
Åslaug Haga, newly appointed oil and energy minister in a government reshuffle (later to be replaced by Terje Riis-Johansen), said her intention was to “make sure that the oil industry is given access to less explored frontier areas with potential for large discoveries”. The licensing round would be “an important contribution to discover the large remaining resources on the Norwegian shelf”.

Nominations were permissible in areas already opened for petroleum activities in the North Sea, the Norwegian Sea and the Barents Sea, with some exceptions: areas already licensed; areas included in the “predefined areas” (APA); especially valuable areas in the Barents Sea, the polar front, the ice edge and Bear Island; the coastal areas of Troms and Finnmark, and Eggakanten, Nordland VI, Nordland VII and Troms II. Government emphasis on fisheries and environmental concerns in the coastal areas meant that conditions for licences had been tightened in some respects, e.g. restrictions on seismic surveys in certain blocks.

By the November 2008 deadline, the Ministry of Petroleum and Energy had received applications from 46 qualified companies, making the 20th “one of the largest licensing rounds ever”, in the words of NPD exploration director Sissel Eriksen, and demonstrating that “new exploration areas on the Norwegian shelf are competitive in an international perspective as well”. Terje Riis Johansen agreed. “It is positive that this many companies want to aim towards new opportunities in the Barents Sea and the Norwegian Sea”, he said. “Petroleum activities that are undertaken in accordance with important environmental and fisheries concerns can make a significant impact on employment, industrial development and value creation in the northern areas.”

Clearly, the gradual exploration strategy for frontier areas has ensured a high discovery rate on the Norwegian continental shelf, where the number of exploration wells spudded has risen sharply in recent years. (A total of 56 exploration wells were drilled during 2008  the highest number ever on the Norwegian continental shelf  and by the end of 2009 that record looked set to be broken.) “The exploration acreage on the Norwegian shelf continues to be attractive”, the NPD writes. “Never before have so many production licenses been awarded on the Norwegian shelf.”

APAs, TFO and EOR
In 2003 the government adopted a new system for allocating blocks in mature parts of the Norwegian continental shelf: awards in predefined areas (APAs, or TFO in Norwegian).

The aim, as the NPD put it, was “to provide greater predictability for the companies and encourage more efficient exploration of the mature regions” while making a larger area available to the industry. An area on Haltenbanken in the Norwegian Sea was included in the first announced predefined area; with a smaller expansion in the North Sea, the acreage announced totalled 143 blocks or part of blocks.

Petroleum activities on the Norwegian continental shelf started in the North Sea and have gradually moved northwards based on the principle of gradual opening of areas. Consequently, large portions of the North Sea are now considered to be mature from an exploration perspective. There has also been considerable exploration of Haltenbanken in the Norwegian Sea, and many parts of this region are also considered mature. The most recent area to be considered mature is the area surrounding Snøhvit in the Barents Sea.

Limited lifetime
The overall infrastructure is generally highly developed in mature areas. Nevertheless, the lifetime of the existing infrastructure is limited and it is thus important to prove and recover the resources in these areas before the infrastructure is shut down. Otherwise, profitable resources may be left in the ground because the discoveries are too small to warrant a standalone development of infrastructure.

Active exploration within licensed areas is important to the authorities. The areas awarded are tailored so that the companies will only get acreage where they have specific plans. The work obligations assumed when companies are awarded new production licences comprise a set of activities and decisions. At each juncture, the company must decide whether it wants to implement new activities in the licence or relinquish the entire area. Relinquished acreage can be applied for by new companies that may have a different view on the prospectivity. This leads to a more rapid circulation of acreage and more efficient exploration of the mature areas.

The predefined areas can change from year to year, but only by expanding. Full or part blocks relinquished to the authorities within these areas are immediately included in the APA. Exploration has long been under way over most of this acreage, but it also includes blocks which have not been drilled for many years. Companies receiving APA acreage must commit to a faster exploration of the acreage than has been or is normal in Norway’s traditional licensing rounds. They also have less time that has been usual on the NCS to assess whether they want to drill or develop possible finds.

The authorities received applications from 16 companies in the first APA round in 2003. The number of applicants has increased steadily since then, with well over 40 companies submitting applications in APA 2007, 2008 and 2009. At the same time, the available acreage in the APA scheme has expanded. APA 2008 included 19 more blocks/parts of blocks as compared with APA 2007. A total of 52,415 km2 distributed among 197 blocks or parts of blocks was available in APA 2007, of which 16,423 km2 was awarded. Since that award, more than 10,000 km2 has been relinquished; this acreage was included in the area available in APA 2008. (However, the APA acreage was not extended for 2009.)