So far the North Sea oil and gas province has proved surprisingly resilient to sharply lower prices. There is concern about the impact of the UK's proposed tax changes but other sectors look strong, Martin Quinlan writes.

For the past eight years, activity in the North Sea's four producing sectors - Norwegian, British, Dutch and Danish - has been on a high. Oil production, averaging 6.2m barrels a day (b/d) last year, has increased by more than two-thirds since 1989, while gas production has increased by half to 223bn cubic metres. Infrastructure has been expanding as rapidly as in the early years; the province has become the driving force for the development of new technology; and exploration and production operations have been extended into much deeper and more remote waters.

But for most of this period North Sea crudes have been selling at relatively strong prices. Last October's downturn, leading to this year's sub-$15/barrel levels for the Brent Blend "marker", therefore set alarm bells ringing in more than 90 producing companies and many times that number of service companies.

Direct consequences

There is no doubt that a long period of low prices will harm the development of the North Sea. One direct consequence will be the deferral of work in new areas, such as the UK's Atlantic margin and Norway's far-north; another will be the early shut-down of fields nearing depletion, with the possible loss of reserves in their vicinity. But, for the moment, projects are still moving ahead. So far this year in the UK sector - the most mature part of the province, and the barometer for the North Sea as a whole - go-aheads have been announced for Shell's Ketch and Corvette, the Texaco, Amerada Hess and Shell jointly-operated Bittern, Guillemot West and Guillemot Northwest fields, Phillips' Delilah, Total's Grant, Amerada Hess's Flora and Mobil's Buckland. These projects are not all small: the Bittern/Guillemot West/Guillemot Northwest development will produce 100,000 b/d at plateau.

The explanation for this substantial level of investment is that, although prices are low, the UK's tax system for oil and gas ventures is the most attractive of any established producing country worldwide. With royalty and petroleum revenue tax long since abandoned for new fields - they were withdrawn in April 1982 and March 1993 respectively for fields going ahead after those dates - companies pay only normal corporation tax on their oil ventures. Even this tax is relatively attractive: the rate is 31%, reducing to 30% in April next year, with oil and gas ventures "ring-fenced" from other businesses. The possibility of changes to the tax system - as promised by the UK's Labour government when it came to power last year - is, therefore, causing considerable concern. The government was due to publish a consultation paper on its planned changes in June, the main options being a re-introduction of petroleum revenue tax or the introduction of a petroleum-specific tax within corporation tax. The changes are expected to take effect in the spring 1999 budget.

Mature areas

The test of the impact of the UK's tax review will be the 18th licensing round, applications for which must be in by 11 September. The territory on offer should be relatively attractive, even in a low-price environment: the round eschews more remote parts of the shelf, where discoveries might be substantial, but development costs will be high, and instead offers blocks in mature areas of the northern, central and southern North Sea and parts of the Irish Sea. Most of the blocks have seen some unfruitful exploration, but most have the advantage of being in the vicinity of existing processing and transport infrastructure. There are, therefore, possibilities for the speedy development of single-well or small multi-well fields, at a relatively low capital cost.

But although such projects are not capital-intensive, their operating costs can be high - particularly if processing or transport have to be contracted from a third party. According to the Department of Trade and Industry's latest Brown Book, the average field-lifetime production cost for fields under development at the end of last year was £7.00/b ($11.70/b). (The figure includes capital and operating costs; takes into account production of condensate and associated gas; includes an equity share of the cost of pipelines and terminals; includes exploration costs with the exception of unsuccessful exploration not attributable to a specific field; and assumes a real return on capital of 10%.)

Small margins

With oil selling for well under $15/b, there is, therefore, only a small margin for additional taxation. There is, apparently, no taxable margin for earlier fields: calculated on the same basis, the production cost of fields which came on stream in 1991-97 is £9.00/b ($15.00/b), and the average for all fields in production is put at £10.00/b ($16.70/b) - although the profitability of fields already on stream has benefited from the higher oil prices of earlier years.

Meanwhile, there are some two dozen fields under development in UK waters, over half of them scheduled for start-up this year. The largest projects under way - both due for imminent start-up - are Conoco's and Chevron's jointly-operated Britannia, expected to flow 6.6bn cm/y of gas and 45,000 b/d of condensate; and BP's Schiehallion, expected to produce 140,000 b/d of fairly heavy crude from deep water west of Shetland. Next year's start-ups include Shell's Egret and Ketch, Mobil's Buckland, and the jointly-operated Bittern, Guillemot West and Guillemot Northwest development; highlights for 2000 will be first production from Elf's Elgin/Franklin and Shell's Shearwater.

Norwegian deferrals

In contrast to the UK government's aim of increasing its tax "take" without slowing the pace of development work, the Norwegian authorities are positively seeking to put a brake on development activity. Governments past and present have aimed at achieving a steady pace of offshore work, partly to allow Norwegian oil service companies to take a high proportion of the work available and partly to avoid overheating the country's relatively small economy. But - the frequency of licensing rounds being a fairly coarse means of regulation - there is now a substantial "bank" of projects coming up for development. Earlier this year, therefore, the government imposed delays on a number of projects in the development pipeline.

The 12 projects now deferred for a year or so are Statoil's Huldra, Yme Beta West, Sygna, Gullfaks satellites and Heidrun North; Saga's Snorre B, H-Central and Tordis extension; Norsk Hydro's Fram and Grane; BP's Ula Triassic; and Amoco's Valhall water-injection scheme. The earliest of these projects will now not be starting up until next year and the others will follow in 2000 and 2001, with the three largest developments - Snorre B, Fram and Grane, with a combined plateau flow of more than 300,000 b/d - being among the last to start producing.

However, although the deferrals were criticised by the operators - most notably by Amoco, which said the delay in providing Valhall with injection facilities will cut the volume of additional oil to be recovered from the planned 150m barrels to 140m barrels it seems that their impact on the overall level of Norwegian activity will not be serious. Of the three large projects, only Snorre B had progressed to the point of having a start-up target (2001), and this is unchanged. Fram and Grane, the latter a complicated heavy-crude field, are both at an early stage of planning, and it is unlikely that they would have been targeted for start-up before 2001 anyway.

Meanwhile, operators are occupied with nine substantial development projects, all scheduled for start-up over the next two years. This year should see first oil from Norsk Hydro's Visund (expected to plateau at 95,000 b/d), Saga's Varg (52,000 b/d), Norsk Hydro's Oseberg East (66,000 b/d), Statoil's Gullfaks South (65,000 b/d) and Statoil's Rimfaks (58,000 b/d). Next year, Esso's Balder (73,000 b/d) and Jotun (80,000 b/d) will come on stream, and in 2000 there will be first oil from Norsk Hydro's Oseberg South (124,000 b/d) and Statoil's Åsgard (227,000 b/d).

These projects will add a combined plateau of 840,000 b/d to Norway's production. According to the ministry of petroleum and energy's forecast, the country's output will increase from the 3.1m b/d (excluding natural gas liquids) of 1997 to about 3.9m b/d in 2001. (The projection for this year is 3.1m b/d, allowing for the 100,000 b/d cut from projected output imposed by the government in support of Opec's price stabilisation plan.)

New fields off Denmark

Activity in the Danish North Sea - in thepast, limited as much by unexciting geology as by a heavy state influence - is seeing something of a boom this year. Three new fields are under development, amounting to a 25% increase in the total of Danish-sector producers, which comprises nine oilfields and three gasfields. Additionally, a new gas-landing pipeline is being constructed, and in-fill development continues at the largest oilfield, Dan.

The three new fields are Mærsk's and Statoil's Lulita oilfield, extending from the Harald field to the border with Norwegian waters, due to start producing this summer; Statoil's Siri oilfield, expected to come on stream by year-end; and Amerada Hess's South Arne oil and gas field, scheduled for start-up in September next year. Lulita will produce to Harald facilities, but Siri and South Arne will have platforms and offshore-loading facilities, making for, a reasonable level of construction work. The new gas pipeline, being implemented by Dansk Olie og Naturgas, will be a 300-km, 24-inch system running from South Arne to Harald, and then on to the Nybro terminal. On start-up, targeted for the middle of next year, Denmark's gas-landing capacity will rise by nearly half to 12bn cm/y.

Five other oil and gas fields, all fairly small and all operated by Mærsk, are being prepared for development subsequently. Adda and Igor are targeted for start-up in 1999, Elly in 2000 and Alma in 2003; Gert, extending into Norwegian waters (where Amerada Hess has named it Mjølner) will be the subject of a new development plan when the two operators have agreed on whether it will produce to the Harald platform in the Danish North Sea or to the Valhall platform in the Norwegian sector.

Netherlands set for upturn

The North Sea's oldest gas province still produces typically five or six small field developments each year, as infill wells are tied back to the two main pipeline systems. This year and next, however, should see an increase in activity, led by the expected construction of extensions to the NGT pipeline (at L/10, to tap Wintershall's D/15-FA field) and to the Nogat pipeline (into German waters, to tap Wintershall's A/6-B/4 field). The extensions will enable a number of small discoveries along their respective routes to be developed - including some in the UK sector, which could be tied back to D/15-FA.

Meanwhile, NAM and Elf have various development projects under way, mostly for completion this year and next. NAM is about to start up new facilities in L/9 which will tap some 23bn cm of gas and will also provide spare processing capacity for possible developments in the vicinity. Elf has four projects under way - K/1-A, K/4-A, K/6-GT and L/4-PN.

Earlier this year, according to the economics ministry, 17 applications for production licences were under consideration - 10 by NAM, three by Wintershall, and two each by Amoco and Elf. Surprisingly, older territory was well represented in the licence applications, two being for third-round blocks (K/3a and A/18a, both sought by NAM), and four for fourth-round blocks (A/12a, K/2a-b andD/18a by NAM and E/13a by Wintershall). The others were one fifth-round block (Q/13a, sought by NAM), three sixth-round blocks (B/16 by NAM, and Q/5c-d-e and B/17a by Wintershall), one seventh-round block (E/12a by Elf), one eighth-round block (P/11b by Amoco), and five out-of-round blocks (parts of A/12, A/18 and Q/16 by NAM, part of K/3c by Elf and part of P/10 by Amoco).