The past 12 months have seen some major North Sea acquisitions (Forties Field), discoveries (Buzzard Field), new entrants and funding packages. It is good news for an industry that has stagnated in recent years while the UK government has attempted, with little success until now, to push the majors into selling portfolios of what are for them uneconomic fields to smaller operators with low overheads.

That the UK oil business needs low cost independents is certain. In 2002 just 33 new wells were drilled, the lowest number since 1971 and equalled only by 1999, according to energy consultancy Wood Mackenzie. And Encana's recent Buzzard Field strike - the biggest in the North Sea since the 1970s - is an anomaly. Future wells will be small, requiring niche players with new technology to get what remains in the North Sea out: estimates run to 29 billion barrels in total.

That the UK government is attempting to re-kickstart the market is also clear. Its attempts to revive exploration through its Promote scheme brought 27 new companies into the North Sea in August. New entrants such as Wham, Carrizo and Energy 365 have been charged cut-price fees of £15 per square kilometre per year for the opportunity to find new reserves: EnCana was the biggest winner with 12 out of 137 blocks.

But recent successes are not enough to make a real impact. The heart of the problem for the UK government is that the majors are hanging on to assets in an attempt to play down production growth targets. The bottom 80% of assets owned by the majors account for as little as 16% to 29% of total company value. The conclusion is that less productive fields are not being run or made available to the niche players with the economics of scale to maximise returns.

The size of the problem is such that last year Brian Wilson, then Energy Minister, issued a 'use it or lose it' warning to the industry, suggesting that licences could be removed from companies with inertia.

An empty threat perhaps, but the pace of change is quickening. Oil majors like BP and Shell have begun to sell up. There is growing interest from the US and Canada in the form of Encana, Talisman, Kerr McGee, Anadarko and Perenco, all of whom are keen to take these relatively low risk assets. And size of interest ranges from the very small like Calgary-based Stratic Energy, which picked up a new North Sea exploration licence in July, to Houston-based Apache which bought the Forties Field from BP for $630 million in early 2003.

In the UK the combination of market consolidation over the past few years, restructuring, advances in extraction technology and the political will to extract from what were fallow fields and stranded reserves, has also spawned some relative newcomers - Acorn, Ramco, Tuscan, Eclipse Energy, Venture. But unlike their US-Canadian counterparts they often struggle with funding.

Funding independents

Tuscan - which is expecting first oil in the next two weeks on its Argyll Field redevelopment (the Argyll Field was originally owned by BP and is now 35% Acorn Oil and Gas and 65% Tuscan) - had to go to the US to get £25 million of its £35 million funding from TCW: Aberdeen Murray Johnstone (AMJPE) put up the other £10 million private equity.

Along with Tuscan - Venture, Highland, Consort, CH4, Faroe Petroleum and ENS are all examples of companies initially backed by private equity. But even when venture capital is available - the cost and tenor can seem prohibitive. As Tom Reynolds, director at 3i (which is in the syndicate seeking to purchase ABB Oil & Gas) says: "from private equity we typically want to double our money in three years."

Consequently many independents - primarily those from the UK - are confronted with a frustrating money-go-round. Being able to demonstrate that funding is in place speeds up the borrower's case for further drilling in a field. But to get bank, rather than venture capital funding, further exploration is often required.

The problem is not that banks will not lend. In October 2002 Credit Agricole Indosuez provided a $20 million senior debt facility to Acorn Oil and Gas to fund its commitments on Argyll.

And while some banks like JP Morgan Chase have largely pulled out of minor oil and gas (although the bank was recently seen back in the market as co-underwriter for Intrepid), the sector is still popular with many niche lenders including Credit Agricole, Royal Bank of Scotland (RBS), Halifax Bank of Scotland (HBoS), Bayerische Landesbank, CIBC and now Macquarie - most of which will also do mezzanine and equity.

The problem is that any deal is done against a backdrop of uncertainty over key issues dogging the whole North Sea market - disagreement over abandonment cost forecasts; gold-plating of existing assets by the majors; fiscal unpredictability and oil pricing. In effect a host of risk mechanisms are called for that, as yet, the market cannot agree on.

Abandonment

Abandonment costs are a major issue for future project economics. An estimated 33% of fields sold now will mature by 2025 and decommissioning costs range from £20 million for a small Southern North Sea structure to £150 million-plus for heavy structures. The total cost for UK Continental Shelf decommissioning is estimated at £15-£19 billion.

As Gareth Hughes at insurer Marsh says: "with a few notable exceptions, it has been, is and will become increasingly difficult to transfer or sell fields on to late life specialists because of decommissioning risks and liabilities."

The benefits to the UK of creating a smooth sales environment are clear. Elf sold Talisman its Piper-Claymore area in 1998 and, after significant operating cost reductions and new well investments by Talisman, field life was extended from 2005 under Elf to 2015-plus.

But as John McCallum, director at Stellar Hannon Westwood Associates, notes: "How many majors have got the cost of abandonment right - can a small company coming in acknowledge that obligation?" The question is clouded further by the fact that "with the independents coming in there are different perceptions of value and the consistent complaint of gold-plating," adds Charez Golvala, lawyer at Vinson & Elkins.

Furthermore the legal regime is designed to do one thing - protect the taxpayer. There is joint and several liability under UK law - although this does not encompass bank lenders. Notices can be served on the installation manager, the licensees, parties to a JOA/UOA, any person owning an interest in the installation, and the parent and other associated companies.

Consequently, for a small independent looking for a license, the security arrangements it needs in place are both complex and expensive. Even for a subsidiary of a foreign owned company, parent guarantees are not acceptable because the DTI does not want to find itself suing a foreign owner.

The risk finance mechanisms to deal with abandonment are numerous but have their own drawbacks or are as yet untenable. A mutual guarantee fund, for example, imposes a disproportionate cost and liability burden on the majors. And although the UK government has looked at creating a climate for sinking funds, for a fund to be attractive to the industry it would need to attract full fiscal relief at the time the funds were set aside. Aside from not wanting to give tax relief, the government has decided that the structure is too open to potential abuse.

Conversely, DGI - as an insured credit default structure behind a LOC or as a standalone - has been accepted by some players in the market. But it is renewable every 12 months and is perceived as a short term fix that at 3-5% annually is relatively expensive.

Finally, there is NSAPS. A financial risk mechanism that, if it does what developer Marsh claims - tax capacity during decommissioning, AA-plus unconditional guarantees to secure third parties without the need for collateral and the possibility of an economic benefit - and is affordable, has the potential for a real solution. According to Gareth Hughes the underlying assumptions on NSAPS are robust. But given the company is keeping the structuring under wraps and has not released a real example of it in use, how good it is remains speculative outside the board rooms of those in the know.

Fiscal risk

Of all the risks faced by independents the general consensus is that the biggest is fiscal/political change. Political cynics might argue that the UK government, having taken an estimated £190 billion in tax since the North Sea started producing, would not be sorry to see the industry become a problem for the new Scottish parliament as soon as abandonment costs and field size make North Sea economics untaxable. And recent governmental moves send mixed messages.

While the DTI has been heavily promoting the sector, UK Chancellor Gordon Brown only added to confusion in the last budget with a 10% tax hike followed later by a cut in royalty payments. And Energy Minister Brian Wilson's replacement by Stephen Timms (Minister for Energy, E-Commerce and Postal Services) does not inspire confidence - clearly the government feels UK Energy Minister is not a full time job and sees cross-over between the three sectors.

Despite the curious set up at cabinet level it is clearly not in the UK government's interest to put too much tax on the industry so that the 29 billion taxable barrels, not to mention gas, left in the North Sea, remain there.

And tax can play a major part in price hedging - potentially a key element in future projects for cash-poor independents. North Sea asset hedging removes much of the future oil price uncertainty, thereby giving borrowers a more predictable income stream - albeit at a fee.

The problem for independents, as demonstrated by Tom James at Credit Agricole Indosuez, is that tax considerations can restrict the amount they can hedge. "For example, the Norwegian government taxes Statoil a massive 78% on North Sea Oil. Consequently the company has been forced to reduce hedging activities to 30% of underlying production from a field because of the tax disadvantage." Tax breaks on special hedges for independents have to be a government consideration.

Despite the relative lack of risk mechanisms around, competitive funding for the established small independents is available. Most recently (July) the smaller partners in the Encana-BG Buzzard development - Intrepid and Edinburgh Oil & Gas - went to the bank market for funding. Intrepid pulled in a $600 million six-year secured corporate credit facility fully underwritten by ABN Amro, HBoS, JP Morgan Chase and RBS.

Pricing was 130bp linked to cover ratios and the loan will fund $400 million of capex and any cost over-runs. The deal also replaces a half-drawn 70bp $220 million revolver from Chase in 1997. According to Intrepid Energy North Sea finance director, Andrew Paxton, syndication is unlikely until next year.

But despite some funding successes, as the volume of independents swells and funding needs push risk sharing further into focus, the industry will either correct itself or the government will have to step in with compulsory legislation at worst and a tax carrot at best. The answer seems to be a risk sharing mechanism between the majors and minors with minimal specific tax breaks thrown in. But as Peter Gaffney, senior partner at Gaffney Cline, notes "the world is full of good non-operator ideas that never see the light of day."