The oil price has been a wild ride for the last three years. After a steep rise in prices between 2006 and 2008, including a sharp spike in the price in the middle of last year, prices dropped sharply, and have only started to recover. Bankers covering the sector, normally at home with volatile commodities risk, are struggling to help producers fill their funding gaps. Refinancing risk has already claimed one victim – North Sea producer Oilexco.

Project Finance assembled a panel of industry of experts to assess where the industry is:

Chris Prior (CP), partner and co-head of the global oil & gas practice, Dewey & LeBoeuf
William Stevens (WS), global head of upstream oil & gas, HSBC
Frank Pluta (FP), head of reserve-based lending Calyon
Chris Longman (CL), director, Challenge Energy
Jeffrey Woodruff (JW), senior director energy, utilities & regulation, Fitch Ratings

Project Finance: Is there a funding gap for small E&P companies?
Chris Prior: I see companies that would like to acquire assets, or that would like to develop the assets that they have, but that are unfortunately coming up against the problem of funding. It is particularly acute amongst those companies with relatively short track records; say they've listed on AIM in the last several years; they've raised what they thought was a considerable sum of money on AIM and they've found out – to the extent that they didn't know it already – that you can burn through cash very quickly. They may even have a reasonable track record, but they will be quickly running out of funding and they are struggling to find sources of funding.
PF: What is your advice to a small E&P in need of funding?
William Stevens: There are junior oil companies out there that do have funding gaps. It is very rare to find a junior that is fully funded in terms of its capex plans, in terms of its exploration plans and so on. I don't think there's been one independent oil and gas company that has not trimmed back on its exploration budget. Recently there has been a bit of a wake-up call. People are asking, "what is the rationale behind offering reserve-based lending as a product?" Essentially, lenders were looking at reserve replacement ratios for these companies and assuming that they will grow ad infinitum. I don't think anybody has really thought about how these facilities are eventually repaid. It's a very tough decision for a lender and a sponsor to get together and for a lender to say, "sorry, you are at the end of the road, your debt amount has peaked and now is the time for amortisation." Traditionally, the view was that companies continued to grow through asset development and reserves replacement and were inevitably taken out by an acquisition where the debt was prepaid. Now we're in a really tense period. E&P companies have been set more stringent conditions across the board, which have been forced on them by a wide bank group. Each bank wants their own more conservative set of assumptions; tougher coverage ratios, lower forecast reserves, lower price decks – all these variables are forcing down borrowing base availability so quickly that for some companies they are not only not able to fund their future plans but they don't have enough liquidity to fund their current commitments. That is the big problem.
Frank Pluta: That is the main issue. Over the last 10 years all the banks were lending on the value of assets but we were not enough taking care of the liquidity situation. Banks have quite rapidly adapted their view on how to assess reserve-based lending and how to assess companies. Most of the time, I don't think that it's a question of whether the oil and gas independents own valuable assets or not but more whether in the coming 12 months they have a liquidity issue or not. There are still a lot of transactions that are going on today in reserve-based lending – definitely for the big guys like Tullow. And if Sinopec hadn't taken over Addax, Addax could have refinanced itself – it is a solid company. It has more than 20 banks in their syndicate, has access to equity capital markets and therefore has the capacity to resist the current liquidity crisis. What is very difficult today is for very small junior oil and gas, companies with just development assets, absolutely no cash flow, and only capex to spend before first oil over the coming 12 or 24 months.
Jeffrey Woodruff: We said in our outlook at the beginning of the year that we thought smaller E&P companies would face this problem and as such would be ripe as acquisition targets. The funding they need would dry up, yet they are sitting on resources that would be attractive for larger players that have been generating free cash flow over several years. I think this year we expect many of these junior E&P companies to cease to exist and be folded into portfolios of larger players.
CP: It is undoubtedly the case, to the extent it has not started already; there will be consolidation among these players and from our perspective we aware of a number of discussions that are ongoing.

PF: Are there any differences to this down cycle and previous down cycles?

FP: Oil prices going down and at the same time banks going down! The first question is 'what is the value of the assets'? It is not specific to this crisis. It hasn't changed over the last 10 years – we've always seen young E&P companies coming on the market and listing on AIM, some of them were fantastic companies; some of them had no real assets – for these companies, of course, it's the end of the dream. For other companies that have valuable assets and strong management, I don't think it has changed a lot. They have survived a difficult period where prices went down to $40. Now it's coming back at $60-70. We just have to be more cautious on short-term liquidity than before.
WS: There aren't as many banks out there in the market. Their conditions are going to be tighter: requiring fully-funded capex plans, zero partner funding risk. Completion risk was almost overlooked, if, say, you owned 20% of an asset in the North Sea you used to be given value without considering whether the parties holding the residual 80% interest could fund their share of development costs.
FP: The problem today is that underwriting has almost completely disappeared, so it is most of the time a book-building process. So if you have a $500 million to $1 billion transaction you need at least three to four MLAs and need five to ten banks to join, and if you can't find them there is no deal. I'm definitely not happy to see banks leave this market! We need more players to be in a position to close big transactions.

PF: Can multilaterals fill in for banks that have left the market?
WS: It is not really a question of finding banks or institutions to fund the gap. If a borrower wishes to increase its facility size in this market, the issue is that if a willing bank is found to provide additional financing, existing lenders within the deal may prevent it from acceding to the deal. Thus, invariably the only way to raise more funding may be mezzanine-type unsecured lending, which at 12% – or whatever they're charging – is going to eat a massive whole in the finances of the company you're relying on to repay the senior facility.
FP: With these kinds of subordinated facilities you are again going to the same banks and potential lenders. What I believe today is that for companies with valuable assets there will be development of high-yield bonds and converts. We have just done that for a company called Maurel and Prom based in Paris. It has producing assets in Gabon. We structured for it a reserve-based facility and on top of that we have just closed a convert. The company is capitalized at roughly $1.5 billion and has assets primarily in one country and a few across wider Africa. It shows that there is access to the market for these kinds of companies. The producer reached first oil just a couple of months ago

PF: What about other sources of funding, such as private equity?
FP: We've not seen that over the last 12 months. What can help a junior oil & gas company today is a group of solid core relationship banks. For instance, the fact that Tullow raised so much money is not just the assets but the way it has managed their bank group over the last 10 years. Secondly, how to fund the gap in terms if cash? Farm outs. I do not see private equity helping out junior E&P companies too much, but farm-outs, yes. That is something very easy in this business and can be done quickly, to get a bit more money and at the same time decreasing the capex commitments
CP: We are seeing a lot more farm outs, and many clients are approaching us which are not in a distressed situation. Companies will have a lot of assets in their portfolio and may only be able to concentrate on one asset at one time. Not only will companies get the money on a farm out, they quite often also get expertise from valued partners, which is tremendously helpful.
WS: You might not get the value you want, but if you're desperate, you may decide you have to concentrate on core assets and may be prepared to offload blocks which may not be such a priority. What's interesting is that there have been a few cases where a number of companies with minority interests have teamed up and then farmed out as a package, which is good, as investors will be less concerned with partner risk.
PF: How are you valuing assets?
CP: What we have seen in the recent past in price negotiations on M&A transactions is a big mismatch between buyer and seller expectations. Buyers are willing to pay less than, say, $30 per barrel of oil and sellers are sometimes still living in a world where it was as much $150. Legal issues tend to take on less significance when you have that large a gap in expectations.
WS: The approach to valuation has changed – there has been a convergence in terms of valuations from an equity perspective and that from a debt perspective. Buyers are giving limited upside value these days and are not giving much value to exploration and costly long-term development. As these value perspectives converge and there is less willingness to give value for upside, this is concerning lenders as they may have given some value above and beyond senior debt's valuation. The risk being that if lenders exercised their security and sold the assets, in this market, it may not be enough to repay all the layers of debt built into the financing.

PF: Given this mismatch in valuation, how does this pressure get relieved? When is a wave of consolidation likely?
JW: We are still in this waiting game, where companies are holding out because they expect this hockey stick recovery. If that doesn't materialize then we will see a pickup in distressed sales, but for now it's about survival mode, it's about hanging on as long as possible so that you're not the one with no chair when the music stops.
CP: It's undoubtedly the case that a number of companies are conserving resources at the moment. So whilst they were going to drill that oil well or do that redevelopment, they are not going to do so in the near term and that has a knock-on effect through the whole industry. Some may argue that is a good thing, because it will lead to more of a realignment between service companies and E&P companies, which has arguably been out of balance for the past few years. Hopefully there will be more of an alignment as oil prices come down and the price firms up. Part of the problem is that at the moment oil is at around $60-$70, but how much belief is in that price? Is there a belief that that is going to go higher, or go lower? Certainly amongst the group of people I talk to there is an expectation that it will go lower and that the current price is based on a certain amount of speculation.
FP: The only question is how low? When forecasts started to go below $40 we looked at our portfolio and ran sensitivities. The target was to assess what would be the breakeven for most of our clients, junior oil and gas companies. Most of the companies in the market for financing today can resist for a certain amount of time prices between $35 to $40 per barrel. I think oil prices are partly driven by producers' capacity to sustain production at this price level. For oil and gas companies operating in the tar sands in Alberta Canada, one analyst said that the breakeven price of oil was $80 for tar sands production one year ago. Six months later the same analyst said the breakeven was at less than $60. Strange, isn't it?
WS: There're two sides to this when you're looking to invest in a project – you look at the oil price and you look at the costs. Costs have been fluctuating wildly: steel prices shot up by 288% between 2004 and 2008 and are now back down to more stable levels; rig rates increased at about the same level. Developers like costs to be as stable as possible; it doesn't really matter if oil prices are $40, or $140, as long as you can keep control of the costs. That's what has killed a lot of people off. For potential acquirers or those companies looking to spend money on new developments, many are waiting for costs to stabilise first. There's usually an 18 to 24-month time lag between oil prices falling and for jack-up, shipping and oil services costs to fall. With cost deflation and with oil no lower than $50 a barrel; it makes things look a lot more attractive for developers, particularly the pre-salt assets in Brazil or the ultra-deep stuff there.

PF: You mentioned falling costs, where are they today?
WS: Jack-ups are falling off the scale; there is a glut of semi-subs as well. Drillships are maintaining their prices. All the big deals are offshore deep water that require drillships, so in terms of capex there has not been much change, say 15% or 10%.
PF: Could the national oil companies (NOCs) spur a wave of consolidation?
CP: Yes, undoubtedly. National oil companies view oil and gas as a strategic resource that they absolutely need. For many NOCs, it has for some time now been part of their strategic plan to acquire oil and gas resources throughout the world. They have persevered in their search for resources and they are now reaping the rewards for that. They are becoming major players in the market.
PF: In terms of reserve-based lending, where was the price deck when oil was at its peak, and where is it now?
WS: Price decks have not moved that much to be honest, even during the time that oil went to $140 per barrel. Whilst the oil price was that high, some price decks were pitched much higher than we were willing to go at the time and we've only accepted a maximum of $55 to $60 as a floor. It is around $40 to $45 today. Any benefit that came from a higher oil price was either applied as a result of any hedging programme agreed with a borrower, or in excess cash which borrowers were able to reinvest into the company.
FP: You could imagine if all the banks had gone crazy and moved the price decks to $100 – we would have killed most of the oil and gas companies in the market today. The banks were pretty conservative.
PF: Where are current benchmarks, in terms of key metrics, for reserve-based lending today?
FP: Over the past two-three years there has been so much liquidity in the market that banks were trying to win subsequent mandates by moving one term in the structure of a typical transaction – either a bit more aggressive on coverage ratios, a bit more aggressive on grace periods. The deals were particularly aggressive in the North Sea. Most of the transactions were considered at the 2P level, which was definitely aggressive, especially when you look at development assets. Now we have moved back to where we were four to five years ago. As long as the asset is technically sound, arrangers are comfortable with how the company and the asset is developed, and we are happy with the sources and uses, there are many transactions that can close today. Even for pure development assets there are transactions that we are working on now.
WS: The two types of deals you will fund right now are very small, limited-scale club deals up to $150-$200 million with three or four banks that are prime relationship lenders. The second type of deal concerns the prolific West African developments currently being financed, where some banks have been prepared to put very large sums on the table. These deals also tend to generate a great deal of event-driven business. It is not just a question of providing debt, there is a whole range of cross-selling opportunities in M&A, commodities, equity capital markets and so on. Lenders recognise that the nature of the assets make them very attractive to NOCs with deep pockets and thus the chances of being pre-paid in the not-too-distant future are very high. As a general comment, in terms of structuring these deals, lenders used to regard borrowing base facilities as finely-tailored, bespoke products that you could tinker with at the edges to maximise value more and more. The reality is if you don't have the fundamentals in place, sophisticated tailoring counts for nothing. The market had gone too far with project life coverage ratio-driven deals, reduced reserve tail ratios, slugs of stretched debt, undeveloped asset-backed loans and multi-tiered facilities on the same assets, part of which is secured, part unsecured. And evergreen clauses essentially based on the assumption that your company would always keep finding reserves and you could push out the tenor of the facility. It became a very large pot of cash without any clear exit route. Some banks will have legacy deals and when it comes to re-determinations each bank will make their own point. One bank wants a lower price deck, one bank wants lower reserves, one bank won't recognise 2P. So the danger is you will end up with all these metrics being shed, so that what was a robust and flexible facility becomes a much smaller less attractive and restrictive product, meaning the client is unable to fund its capex plans and must dedicate all its cash to repayment. There is a risk that this liquidity crisis can sink some pretty healthy companies just because they have debt.
Chris Longman: And that has happened already – has it not? With Bow Valley Energy. Bow Valley was taken over by funding from the same bank but wearing a different hat. [Dana Petroleum bought Bow Valley in mid-February 09 for $177 million including $142 million net debt financed by a $400 million revolving credit facility from Bank of Scotland. Including Bow Valley's tax losses, the net acquisition cost to Dana was around $9.47 per barrel].
FP: Yes, but as you say, they were taken over. Which shows they had valuable assets and banks didn't lose money.