Falling Oil Prices and Upstream Insolvency Risk

Falling Oil Prices and Upstream Insolvency Risk

February 18, 2015

By Kevin Atkins and John Verrill

Collapsing oil prices are affecting projects and companies in the oil and gas sector.

This article looks at how upstream joint ventures typically deal with the risk of partner insolvencies and, in particular, what rights host government and joint venture partners have upon an insolvency of a co-venturer.

Licensing Regimes

There are broadly speaking two main types of upstream licensing arrangements: concessions and production-sharing or service contracts. Aside from certain US states (such as Texas and New Mexico) where title to oil and gas vests with the landowner, host governments almost always have legislation vesting title to oil and gas with the government, whether onshore or offshore, up to the limits of the continental shelf. The licensing arrangement is the means by which the host government grants oil and gas companies the rights to search, drill and produce oil and gas. Without a licensing arrangement with the host government, no upstream oil and gas project can exist.

The concession structure is commonly used in Western Europe and the United States. Under such a structure, oil and gas companies take title to production, and the host government’s revenue stream is then derived from fiscal terms (such as royalties and taxes) charged on production. However, under the production-sharing and service contract structure, oil and gas companies do not take title to any of the oil and gas produced because title remains with the host government. The oil and gas companies only have an economic entitlement to a pre-determined share of the production or in the proceeds of sale.

Under the terms of any licensing arrangement (whether under the concession structure or the production-sharing and service contract structure), host governments will be entitled to terminate the license upon an insolvency event of the oil and gas company. However, where more than one oil and gas company is participating in the upstream project (as is almost always the case given the scale of financial commitments involved), the insolvency of one licensee does not always give rise to an automatic termination right over the entire project.

For example, certain production-sharing contracts in Africa do not give rise to termination rights in the event of the insolvency of fewer than all of the licensees if the project can still be funded and work programs fulfilled. In the United Kingdom, on the other hand, the insolvency of just one licensee, out of a number of other licensees of the same license area, triggers an automatic termination right. This makes the selection of joint venture partners in an upstream project, whether as part of a bidding round or as part of an approval of an entry of a third party into the joint venture, incredibly sensitive. In some cases, joint venture partner approval rights can hold up entire corporate sale transactions if those joint venture partners are concerned about the financial strength of the proposed incoming oil and gas company. As a matter of English law, even absent an express approval right, concerned joint venture partners have an effective de facto approval right if the sale transaction is conditioned on or otherwise requires novation documents to be signed by all concerned joint venture partners. Any failure or refusal to sign the transfer documents is tantamount to a separate approval right.

Joint Venture Arrangements

Pursuant to the terms and conditions of licensing arrangements, obligations of licensees are generally joint and several. Therefore, one of the key drivers behind upstream joint operating agreements is to allocate risk on a several basis between the oil and gas companies in the joint venture and to separate the joint liability regime under the licensing arrangement into percentage interest shares in the upstream project.

This severance of interests also means in the UK that each company is responsible for its own taxes since it lifts its own percentage share of oil and also has the benefit of tax losses from its proportionate share of costs.

The separation of obligations works between the oil and gas companies only and not against the host government that awarded the licensing arrangement, who remains free to pursue claims against any or all of the companies in the joint venture and will be most likely to take action against the companies that have the deepest pockets.

Project costs are funded by cash calls made by a joint venture party who is appointed to carry out the work, usually called the operator. Each joint venture party pays cost and lifts oil in proportion to its percentage interest share in the upstream project. Cash calls are usually made in order to fund the costs of work programs that have been agreed between the joint venture partners on the basis of a voting procedure set out in the operating agreement. This means that, to some extent, joint ventures can control the timing of expenditures by agreeing to work programs that are not especially onerous, provided, of course, that any commitments to the host government are satisfied. Typically, a cash-strapped joint venture party will want to slow down payment and will be reluctant to approve new work programs that it believes it may not be able to afford. However, during the initial exploration phase of an upstream project, mandatory minimum work commitments will be required that will obviously necessitate significant capital expenditure that cannot be avoided.

Any failure to pay a cash call will be treated by the operating agreement as a default. Where one party is in default, the other parties to the joint operating agreement will be required to pay the sums that are in default, each in the proportion that its percentage interest bears to the total of the non-defaulting parties’ percentage interests. Any failure to pay these additional sums will itself be treated as a separate default. The defaulter will have his interest carried so that the project can continue, but default will also put additional strain on non-defaulting parties.

The consequences of a default usually escalate over time, with forfeiture being the ultimate and final remedy to the non-defaulters.

The default usually begins with the defaulting party having restricted rights under the joint operating agreement. For example, it will not receive joint venture information or be entitled to attend and vote at joint venture meetings or exercise any pre-emption rights or even take its share of petroleum. If the default continues for a further period of time, then the defaulting party may be obliged to forfeit its interest completely and transfer its interest to its co-venturers. This will obviously only apply to the particular project on which the default occurred and will not generally affect other projects that the defaulting party or its affiliates have interests in, provided that the party is not in default under those projects, too. However, there will almost always be cross-default provisions in the financing documents that will need careful scrutiny.

In addition, in some joint operating agreements, each joint venture party may be bound to grant a security interest to each other co-venturer over its percentage interest in the project, with the co-venturers being entitled to enforce that security, if a party defaults, and sell the percentage interest to realize the amount owed by the defaulting party. This is in addition to the lien on petroleum from which non-defaulters may recoup cash paid out on behalf of the defaulter. However, the nature and enforceability of such charges remains largely untested and, to date, we do not know of such a provision having been invoked in an international upstream project. In any event, as with any security interest, it is important that such security is perfected as a matter of law by the security holders registering particulars of the security in accordance with local laws.

Unlike licensing arrangements, joint operating agreements quite commonly do not include a specific termination right upon an insolvency of one of the joint venture partners. This is because of the fundamental difference in bargaining power and purpose between a licensing arrangement and a joint operating agreement.

Under a licensing agreement, the bargaining strength is typically with the host government, which normally has a number of interested bidders for acreage in a licensing round. The focus of the licensing agreement is the extent and scope of duties and obligations on the oil and gas companies with a view to maximizing host government revenues and the tax take such that, if and when those things are at risk (for example, upon an insolvency of one of the joint venture partners), the host government can terminate the arrangement and seek new joint venture partners as licensee.

A joint operating agreement is more collaborative with the focus being on the integrity of the project in question and how to carry out operations and bear liabilities for the project with a view to a long-term and sustainable, successful and prosperous operation of the project; hence, parties are under an obligation to step in and remedy the defaults of others. Accordingly, insolvency is not itself a trigger to terminate a joint operating agreement. Additionally, in some jurisdictions ipso facto termination for insolvency is unlawful under insolvency laws, but not in the United Kingdom.

Insolvency scenarios

Notwithstanding the contractual rights discussed earlier, in practice (in the UK at least), license revocation in the event of upstream oil and gas insolvencies is uncommon and, in the most recent insolvency in the North Sea, the UK government worked with the oil and gas company and the joint venture partners concerned to maintain the project as opposed to immediately looking to revoke the license. The political desire to pursue further development of the North Sea, and the awarding of tax reliefs in frontier areas (such as the West of Shetlands) and the issuance of new variants to the traditional licensing structure to facilitate continued development (such as frontier and promote licenses that lessen the burden on licensees during the initial exploration phase), also emphasize the desire to keep upstream projects alive. Consequently, prepackaged sale arrangements are generally preferred exits from formal insolvency proceedings as they ensure that the project continues in the hands of a viable third-party purchaser and, if done quickly, will reduce any administrator’s risk of becoming personally liable for oil and gas operations.

In practice, even though joint venture partners have the right eventually to forfeit and effectively to take over a defaulting party’s percentage interest in a project, the reality is that they will not force forfeiture unless there is a commercial rationale for doing so and they have the financial means to step in and fund the enhanced percentage interest share they will be assuming in the project.

One issue with the obligation on co-venturers to step in and remedy the default of a defaulting joint venture party is the funding parties will be unsecured creditors of the defaulting party who may also be insolvent or approaching insolvency. Therefore, funding co-venturers may seek to prioritize their claims over and above the claims of other creditors, but since the funding obligation is in the operating agreement from the outset, this is a desire not always achieved in practice. Why should the defaulter agree? Moreover, the defaulter’s bankers will not want, at the time of most need, to see their security eroded. Indeed, most will have sought subordination of the joint operating agreement liens and other co-venturer protections as a condition for funding the project.

Falling Oil Prices

There are a number of reasons for the drop in the oil price. However, perhaps the biggest single reason is over-supply as the high prices of the last four to five years and the boom in shale gas have caused production to increase significantly and oil and gas to flood the market. The return of major oil players such as Libya, with its close to one million barrels per day, and Iraq has caused supply to outstrip demand and has given consumers a number of alternative sources of supply.

The dip in the Asian economy and the fall in Asian demand has also had a drastic effect on prices and contributed in large part to the over-supply problem. This is coupled with the stuttering European economy.

OPEC in-fighting is also rumored to be a cause of the price drop as members have, over the last few years, been fighting with each other to capitalize on the growing Asian demand and are now fighting to maintain their shares of that market and refusing to reign in production levels to alleviate the problem of oversupply. Politically, some of the cause for concern of the OPEC members may be driven by the US shale boom as US energy independence has removed a previously-buoyant sale market for OPEC crude, and some commentators have suggested that OPEC members are prepared for the oil price to drop as low as $35 to $40 a barrel for quite some time, which would drive competing producers out of the market, before taking steps to reduce production levels.

Effects of Oil Price Drop

Collapsing oil prices will bring upstream projects closer to their break-even points, with costly deep-water projects in pre-salt basins (such as offshore Brazil and Angola), in particular, being at significant risk.

This means that projects may no longer be economic as revenue streams from sales are no longer enough to offset funding obligations. Projects in emerging markets that adopt production-sharing contract arrangements will take longer to recover their capital expenditures from the proceeds of production, which will prolong when they are able to become cash positive. Host governments will also find that proposed licensing rounds are less active than previous rounds as oil and gas companies are unlikely to take on new projects with heavy exploration commitments at a time of falling oil prices. This is already rumored to be the case in Mexico where onshore projects, which generally achieve production faster than deep-water projects, are looking less attractive as production will be monetized at current sales prices. This may mean that host governments consider either suspending or postponing licensing rounds or, if oil revenue is a core component of the local economy, offering more competitive license and fiscal terms to incentivize the continued development of upstream projects. At the very least, it is likely that oil and gas companies will re-assess their portfolios of projects and, where possible, seek to pursue less risky onshore projects as opposed to offshore drilling campaigns, as can be seen recently by a number of oil and gas majors, including BP, Chevron and Statoil, who have reduced their budgeted exploration capital expenditures for 2015.

The drop in price will cause lenders to think twice about offering credit lines to exploration-focused oil and gas companies as exploration risk will be compounded by the lower revenue stream if a discovery is even found. Additionally, existing loans will be stress tested as the ability of oil and gas companies to satisfy debt service covenants (in particular loan-life and project-life coverage ratios) will be scrutinized. Lenders may look to syndicate loan exposures to broaden the risk-sharing profile and reduce their shares of funding particular projects (although incoming lenders are unlikely to accept such risk without some quid pro quo from the syndicating lenders).

This may eventually lead to events of default and acceleration rights and enforcement of security under loan arrangements.

However, to the extent that asset-level enforcement is pursued, this will require the prior consent of the host government as enforcement over the shares or assets of an oil and gas company effectively constitutes a transfer of the interests in the project to an incoming third party, which is routinely subject to the prior consent of the host government. Host government consents for transfers of interests in oil and gas projects are, as a matter of local law, typically subject to the technical and financial competence of the incoming party. In the case of a lender enforcing a security interest over an asset, the lender will rarely be considered to have the appropriate technical competence to conduct an oil and gas project. Therefore, in practice the host government will likely work with the lender to locate a suitable third party buyer for the asset in order to facilitate a sale for the lender to realize the debt owed to it.

Where credit lines are squeezed and funding arrangements pulled, oil and gas companies will look to make their asset bases leaner and may look to corporate partners and potential joint venture arrangements to share the risk of capital-intensive operating expenditures. However, the buyer’s market will be tight as not many investors will look to take a stake in a commitment-rich project that is in the exploration stage at a time when revenues are falling. This may mean marketing to specific buyers in the cash-rich Asian market (although Asian demand is falling and growth rates are slowing) or otherwise seeking partnerships with national oil companies that can manage relationships with host governments, although national oil companies are frequently funded during the exploration phase, meaning that they do not pay their percentage interest shares.

An alternative to debt finance is to seek equity capital from existing shareholders by way of a rights issue or from new investors by way of an offering. However, this will bring its own set of issues as each incoming shareholder will require specific veto rights and board seats and exit strategies that will affect the broader corporate strategy of the oil and gas group. This will also bring any shareholders with different investment profiles into direct conflict with each other and could lead to stalemates with board and shareholder decision-making leading to analysis of shareholder agreements to see how such issues are resolved.

The drilling rig and oilfield services markets may also suffer as assets are either under-worked or given up by joint ventures withdrawing from projects. The assets most likely to be discarded are those in the exploration stage where drilling commitments are mandatory and substantial financial sums are required. This will mean that drilling rigs and service operators are left underutilized, and supply will exceed demand. This will, as a result, affect fleet prices and oilfield services charter party rates and could, in the long term, have an adverse effect on new ship building projects in the Far East. This will also have a consequential effect on oil-dependent projects such as refineries and associated infrastructure that will be postponed as project economics cannot be supported.

Falling oil prices could also re-energize the debate about delinking the natural gas price from the oil price as shale gas players will not want a fall in oil revenues to cause a similar fall in gas prices, especially as the steadily-increasing supply of gas in the global market has resulted in natural regional hub pricing. However, unlike offshore deep-water crude oil projects and the heavy sour crude oil projects that require a large refinery expense, a vast majority of onshore US domestic shale projects can still remain cash positive and above the break-even line despite the fall in process, although a sustained drop to a sub-$50-a-barrel figure would test the economics of even those shale projects.

A long-term drop in the oil price will have a devastating effect on resource-rich economies, a number of whom are OPEC members, and may lead to widespread redundancies by major oil and gas companies. For example, certain oil and gas companies active in the UK North Sea are already talking about mass layoffs in 2015, and a number of North Sea investors are whispering about the imminent collapse of North Sea prospects.

However, broader global geopolitical concerns may be relevant, too. For example, the Russian economy is heavily supported by oil and gas prices, and the lower oil price is having a disproportionate effect in Russia and is compounding the effects of the existing US and European Union sanctions that restrict, among other things, capital raising and oil and gas exploration and production activities and sent the Russian ruble into a freefall against the US dollar. This may mean that the drop in oil price is not seen as that bad a price to pay by the US as it imposes extra pressure on the Russian economy.

On a longer-term basis, the US 2016 election cycle will start in earnest in 2015. If the oil price continues to drop (or even if it just stays at below the $65 mark), unemployment will rise in a number of key electoral college states with active shale gas projects (such as Texas and the notorious swing states of Ohio and Pennsylvania). Accordingly, the US may put pressure on OPEC to cut production and let the price normalize as each party seeks to give its presidential candidate the best possible chance of success and push responsibility for the low price on the other party. Whatever happens, 2015 will be a very interesting year as the oil and gas industry and world leaders respond to the market.