"Rumours of my death have been greatly exaggerated." The day began aptly. Chris Prior, partner at LeBoeuf Lamb Green & MacRae, was quoting Mark Twain to describe the outlook for oil and gas companies active in the North Sea. As the oil price remains buoyant, so does the market for North Sea licensing blocks.
"Although the costs are relatively high and the easy oil has already been found," says Prior, "I view the picture as a glass half full. The North Sea is a good and safe environment, which offers great opportunities for lean and hungry E&P [exploration and production] companies, as the majors have withdrawn."

The importance of the remaining and undiscovered oil and gas in the North Sea is not lost on the UK government. Peter Carter from the Department of Trade & Industry (DTI) explained that the UK moved to being a net importer of oil mid-2004, and will move to being a net importer of gas by 2009. The DTI's goal is to "maximise the economic benefit, and contribution to security of supply". Every winter in the UK, security of supply comes up in the press and it is little surprise that nuclear is now seriously being considered as a viable alternative.

The DTI, under its Pilot scheme, aims to maximise recovery of oil and gas by freeing up unworked assets (so that it is now difficult to sit on a licence), reduce late field life barriers, facilitate better access to data such as pipe tariffs, standardise agreements and foster cross-border developments such as the UK/Norway Treaty.
Through the voluntary commercial and infrastructure code of practice the DTI is trying to eliminate barriers to entry, provide arbitration when deals turn sour, and facilitate faster negotiations. It appears to be working – in the 24th round of offshore licensing, 25 completely new entrants to the North Sea participated. (More about the Pilot scheme can be found at www.og.dti.gov.uk and www.ukooa.co.uk)

Rocking Norway

Like the DTI, the Norwegian government has also been grappling with the issue of eliminating barriers to entry for its offshore assets. The continental shelf off the coast of Norway is perhaps about 10 years behind where the North Sea is now, and offers excellent opportunities for small and medium E&P companies.

"New players are welcome offshore Norway to break the hegemony of the three entities – Statoil, Hydro and state control – which control 75% of production," says Andrew Armour, executive chairman, Revus Energy.
The Norwegian tax treatment of E&P companies, which at first glance appears onerous, has become very generous for new entrants. In effect the Norwegian government is 78% partner to all oil and gas companies in its waters – it takes 78% of profits and companies can deduct 78% of their costs. A recent change in legislation now allows E&P companies to set off 78% of their costs even if they have yet to secure production.

This change in the law has led to an explosion in new entrants. The change is extremely helpful to smaller companies without production, because to have any chance of winning a licence they have to adhere to the stringent pre-qualification provisions – they must show operational competence, even though they may not intend to operate and come in as a minor investor. To pre-qualify it is likely a company will need around 10 salaried specialist staff, such as a geologist, finance expert, engineer etc. – these are high overheads for a non-producer to meet, which have been alleviated by the tax change.

The rationale behind the stringent pre-qualification requirement is to dissuade pure speculators wishing to take a punt on the oil price, and prune new entrants to genuine oil companies with the requisite operational expertise.
While the dollar per barrel accruing to an E&P company operating in the North Sea is about $25 a barrel, depending on the geology in Norway it ranges from about $5 to $15 a barrel. "But," says Armour, "the ratio to cost of finding to how much it's worth is the key figure here. Our operations have about 25 cents to the barrel finding costs."

As Richard Wilson of the Oil & Gas Independents' Association points out, the UK finding costs are comparatively high compared with its European neighbours: UK costs are 5x Norwegian costs pre-tax and 12x post-tax, and UK costs are 2x Dutch costs pre-tax and 2.2x post-tax.

Stretching the funding

While the Norwegian tax regime has become much more beneficial to new entrants' balance sheets, a growing company will need to tread a tightrope raising funding – not giving too much equity away to private equity and raising the cheapest possible debt.

Andrew Armour described how Revus Energy successfully negotiated its way to securing private equity, a listing on the Oslo exchange and a five-year NOK300 million ($47.8 million) bond issue. In the UK the most competitive source of funding, particularly given banks' penchant for oil and gas assets and our position in the credit cycle, is probably reserve-based lending.

At the frontiers of reserve-based lending is the hybrid deal that combines mezzanine debt and a senior stretch facility for development projects. Those companies with multiple assets benefit from diversification, lower coverage ratios and lower pricing.

Stuart Jones, director of upstream oil and gas at Bank of Scotland, explains that the typical borrowing base facility has ratios of 1.5x project life cover ratio (PLCR) and 1.3x loan life cover ratio (LLCR). He adds the typical ratios on stretch products come in at about 1.3x PLCR and 1.1x LLCR.

The purpose of stretch products is to go beyond where standard senior lending can go, by plugging the gap between senior lending availability and equity to, say, fund cost overrun risk on field developments.

Mezzanine comes in at below the senior stretch ratios, normally at about 1.2x PLCR and 1.1x LLCR, and uses a reduced reserve tail and the price deck for oil (the base-case oil price assumption that modelling is based on) is increased. Mezzanine usually has a quasi-equity upside, with banks targeting an internal rate of return through a redemption fee, equity kicker or royalty. "Mezzanine financing is still going to be cheaper, we believe, than going to the [equity] market to raise funding," says Jones.

Cheap sources of funding such as senior and subordinated debt instruments, and easier access to equity via an AIM floatation, have helped new entrants to the North Sea and Continental shelf grow organically – but what about acquisitions and divestitures?

From major to minors

Stuart Jones says that the deal flow for acquisitions and divestitures (A&D) has been cyclical, and that he expects A&D activity to pick up as the valuation differences between buyers and sellers narrow. Asset and corporate transactions in the North Sea have fallen from the levels in 2000 and the late 90s, when corporate activity was characterised by mega-mergers and subsequent rationalisation. The low-level activity in the years following 2000 has been punctuated by the occasional, mainly corporate, high-profile transactions, says Mark Llamas, managing director of A&D at Tristone Capital.

Despite the plateauing prospects for North Sea development, the transfer of assets from the majors to large/medium-sized independents has been slow, explains Llamas. In 2002 the majors controlled 64% of the reserves, and in 2005 this has fallen only slightly to 60%. In 1995 the top 5 companies – BP, Shell, Exxon, BG and Elf – controlled 50% of the assets. And in 2005, the top five companies – BP, Shell, Exxon, Total and CP – control 48%.

In the period 2003 to 2005 there has been in effect a moratorium by the majors on divesting any producing assets while they harvest the strong oil price – this has severely restricted A&D flow.

The high oil price has driven asset prices higher, and the increased volatility has stifled divestitures. The price of producing assets has increased in line with oil prices, while development assets have proven less volatile. The most notable recent deal is Endeavour International's purchase of some of the UK-based producing assets of Talisman in the central North Sea for $414 million in cash. The purchase, at the equivalent of $23 per barrel, is by some margin the most expensive transfer of North Sea assets.

Llamas says that as producing asset prices have increased, so too have the acquisition metrics backing the deals. "Historically assets were valued on a P [1P] plus P [P2] basis. Now there is a layering of value on base case valuations." This invariably means that P2 reserves are fully priced in, and some value is given to P3 and exploration, when before there was none.

Llamas adds that increased demand for producing assets has resulted in more aggressive screening criteria, such as elevated oil price assumptions, and non-compliant bidding. Now, unsolicited bids are much more commonplace.

The outlook for the immediate future is the ongoing transfer of assets, albeit at a slower rate than historic highs. Llamas suggests that some transfers may involve innovative deal structures in which the major sells a material position but retains exposure to the upside. Such collaborative investments preserve some of the majors' future production capacity without adding additional capex to their balance sheets. BP has negotiated such deals with EDP, and Newfield and NAM (a Shell and Exxon joint venture) have a collaborative investment with Northern Petroleum in the Dutch sector.

The common theme for these deals is that the smaller partner funds the exploration and development costs, and recoups the cost plus an agreed amount of profit (say 130%) from the cash flows from the movement of first oil. When this cost has been recouped, then production is shared with the major.

The stimulus to divestiture?

The final factor determining the future level of A&D activity in the North Sea is the current UK fiscal environment. And tax expert Gordon Aird, a director at Piper Consulting, is calling for the UK government to amend the current tax regime.

At present the tax regime makes it unwise for a profit-rich major to offset any decommissioning liabilities against its tax pool when it sells on an asset, even if it ring-fences or alienates those costs in a trust. This means that there is little tax incentive for a major to sell on North Sea assets before decommissioning. Aird says this is because decommissioning costs under the present legislation are incurred when the payment obligation is unconditional, the works to be undertaken are definite and the payment is irrevocable – this means when the work is actually performed, and not when the cash has changed hands.

Any attempt to alienate funds is not regarded as costs incurred and is likely to be liable for tax. The asymmetry of this approach at the Inland Revenue is further compounded by the fact that using alienated funds for decommissioning is regarded as a subsidy, which means that no tax allowance is available when the costs are due.

The commercial realty dictates that it would be beneficial for the majors to ringfence decommissioning costs when they sell on assets so that for tax purposes they can deduct these against their large profits at the time of divestiture. Most of the potential buyers in the North Sea do not have the balance sheet or similarly-sized tax capacity with which to set off the decommissioning costs, so a change in the law would encourage the majors to sell, by lessening their tax burden and making the assets with commissioning costs taken out of the equation more palatable to potential buyers. These buyers, invariably smaller, may also be better at maximising extraction and maintaining assets (a primary aim of the DTI) because such production assets would make more of an impact on their bottom line.

Aird says: "The current law stands in the way of mature asset transfers – new initiatives are urgently required."