SpeakingOilGas

Participation

Most agreements now include participation rights for the national petroleum company. For instance, the national company may be ‘carried’ through the exploration stage (i.e. the international oil company will pay the national company’s share of exploration costs) and then be given the option to participate in the production phase.

The arrangement may specify that the international oil company is able to recoup payment of the national company’s percentage of exploration costs through a future share of its production, but often not. Usually, however, the national company will pay its own way in production and development costs. Sometimes the international oil company will market the national company’s share of production on its behalf, but often the national company is large enough to do that for itself.

Permit applications

The method of application for exploration permits generally falls into two categories — tender in response to an invitation (or gazettal) and by direct application at any time.

•Calls to interested parties for gazetted (publicly advertised) areas are generally made known through government or trade journals

and notify	the	petroleum industry of a government’s intention
to licence	new	permits. The size of each permit is specified.

The notice sets a deadline for explorers to consider the areas on offer and make applications as well as informing them what type of bid is required. In countries like Australia, Britain and the USA (offshore) the gazettals will be held at regular intervals — usually once or twice per year. Often the government will also make available a data package of geological information about the areas in question to aid potential bidders in their decision making.

The most common bid application is a work program bid whereby companies submit an indication of the type and amount of exploration work (research, surveys and number of wells drilled) they intend to

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carry out if their bid is successful. This is accompanied by financial and technical bona fides. The government department (or national petroleum company) responsible then makes a decision based on this tendered information. This is the usual bid system in Australia and Britain. Generally the company with the largest work program in terms of expenditure wins the permit and is obligated to carry out, as a minimum, the work program tendered. In some places, such as onshore Australia, Papua New Guinea and Canada, the successful applicant must also come to an agreement with the traditional owners of the land under Land Rights legislation before the permit award is made final.

The work program system also provides the successful bidder with an option to renew the permit (after mandatory relinquishment, usually of 50 per cent of the area) upon expiry of the initial term. In addition, the regulatory authority has the capacity to waive, vary or grant a deferment of work programs and/or relinquishment conditions of the permits.

A second system is a straight out cash bid. Companies bid an up-front amount and send it, with their bona fides to the regulatory authority — like a sealed-bid auction. A work program is also submitted, but this is a secondary consideration. The highest bidder wins. This system is commonly used offshore USA and only entitles the winner to one permit term. There is no option to renew.

A combination of the work program and cash bid occurs in some countries where the company awarded the permit on a work program basis is also required to pay the host government or national petroleum company a cash signature bonus to secure the title.

•Direct application involves an eligible company (or person) applying for a permit to explore land that is not covered by an existing permit, and that is not the subject of intended government gazettal or excluded for some other reason, such as being in a national park or other heritage land. The application can be made at any time.

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Usually the applicant submits an intended work program along with financial and technical bona fides. The regulatory authority reserves the right to grant or refuse the application as well as the right to vary the size or shape of the area applied for and to set minimum work conditions. Again, if onshore Australia, traditional owners must be consulted and an agreement reached before the permit is awarded.

In the special case of onshore USA, companies must make agreements concerning access to land and payment of fees, as well as future production royalties, to the owners of the petroleum rights (if different from the surface owners). To make sure all relevant owners are contacted, companies employ landmen whose specific job is to trace and make deals with everyone concerned.

In some jurisdictions, such as Australia and Britain, successful explorers need to apply for a production licence before being able to develop any discovery, but usually this is a formality and rarely denied. The application sets out the proposed development plan and includes a full environmental study outlining the effects of development on the area concerned. It also contains native land rights permissions (in Australia, Papua New Guinea and Canada for instance) if they have not already been incorporated in the exploration phase.

In PSCs the right to proceed to development is enshrined in the original agreement, but development plans and environmental studies must be submitted before a go-ahead is given.

The geological and geophysical data acquired during exploration and development programs must be submitted to the regulatory authority but, in general, it remains confidential, unable to be accessed by rival exploration companies for a number of years (usually two). Any interpretations based on that data remain confidential, for an average of five years.

All permits (whether granted for exploration or production) require compliance with applicable rules and regulations, including those relating to safety specifications, environmental considerations and other technical requirements, as well as the restoration of the permit area to its original state (this includes the sea bed offshore) at the end of the permit term.

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Tenure and permit sizes

The tenure of permits varies from country to country, but the average duration for an exploration permit is six years. Some jurisdictions allow for several renewal periods of five or six years with 50 per cent of the area concerned relinquished at each renewal. A production permit is generally granted for an average initial period of 21 years, with renewals granted for as long as production lasts.

In some jurisdictions, such as offshore Australia, provision is made for discoveries which are not commercial at the time, but that may become viable for development in the future. The companies concerned can apply for a retention lease around the discovery which requires no, or minimal, work commitments. This lease has an average duration of five years, with up to two renewals of five years each. However at each renewal the company must demonstrate why the discovery is non-commercial and yet still holds the potential for future development.

The actual area encompassed by an exploration permit is usually determined by the regulatory authority in the country concerned. The permit boundaries are usually guided by parallels of latitude and meridians of longitude, but sometimes the boundaries follow geographic features like rivers and coastlines. In rank wildcat areas where there has been no previous exploration, the permits can encompass tens of thousands of square kilometres. In more mature areas the permits are smaller and the boundaries are irregular, to take into account areas that have been previously relinquished.

Where geology is relatively well known, the authorities try not to place a permit boundary through a subsurface structure that has potential to contain hydrocarbons. A discovery that crosses a permit boundary usually requires the companies concerned to make a sometimes complicated unitisation agreement that apportions interests in line with the percentage interests of each and the proportion of the field on each side of the boundary.

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The area of production and retention leases is much smaller than that of the exploration lease as they encompass only the region immediately surrounding the discovery. They are excised from the surrounding exploration permit and again the boundaries are generally based on lines of latitude and longitude. Usually the company makes a judgment about the size of the area it wants to apply for, but the ultimate area is determined by the regulatory authority.

Farm-ins

A farm-in is a way in which a company, individual or group can join a licensee in an exploration or production permit. The move involves commercial negotiations between the incoming company (farminee) and the company, individual or group already in the permit (farminor) which is willing to farm-out some of its percentage interest.

The entry sometimes involves a straight cash settlement and/or a grant of company stock, but the more usual case is that the farminee undertakes to pay for all or some of the work program in the permit to earn a percentage interest from the farminor. The farminor is thus financially carried through that particular part of the program.

Most farm-in/farm-out negotiations are done with the knowledge and permission of other interest holders or joint venturers in the permit. Nevertheless, any negotiated agreement must have the approval of the regulatory authority before the new interests can become effective.

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Other interests

A member of a consortium which actually pays its percentage of program, whether it be survey, drilling or development, and enjoys a proportional part of the resultant benefits, is said to have a working interest.

Other companies may have an override interest which is negotiated with one or more members of the working consortium and is usually a percentage of production, in cash or in kind. Usually this occurs when a company holding the initial licence sells all its working interest to an incoming party in return for an agreed percentage of the proceeds from any commercial discovery.

A third type is net profit interest where a company negotiates a percentage of the net profit from production after deduction of royalties and other charges. This often has a strict legal framework drawn up, and the deductions can vary from case to case.

Pipelines

Although pipelines are often a part of a field development program, licences to build and operate petroleum pipelines are quite separate from production licences and are usually applied for under separate legislation. The application for a pipeline permit must include a detailed map of the proposed route as well as the construction plan. It must also include environmental studies for all sections of the proposed route and must have permissions from all affected parties along that route, including native title and other landholder agreements.

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Chapter 6.

PUBLIC REPORTS & REPORTING

Stock exchanges

Listing

Petroleum companies, in common with companies of every endeavour, may choose to list on a stock exchange principally to raise money in the public market place. Some companies with operations and/or shareholders in a number of places around the world choose to list with more than one exchange so they can raise funds in different capital markets and give shareholders the convenience of trading locally.

Stock exchanges that are often used by resources companies are the London Stock Exchange (LSE), New York Stock Exchange (NYSE), Australian Stock Exchange (ASX), Johannesburg Stock Exchange (JSE) and the National Association of Securities Dealers Automated Quotation — better known as NASDAQ. Smaller companies sometimes choose a listing on an exchange

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that specialises in the smaller end of the market, such as the Alternative Investment Market (AIM) in London which was begun by the London Stock Exchange in 1995.

Listing requirements

As part of the listing requirements for all stock exchanges, companies are required to submit a number of reports about their activities. The general rule in the UK and Australia is to notify the exchange immediately in order to inform the market about any inside information that may affect the share price. This is known as continuous disclosure and may include events such as petroleum discoveries and takeover bids. Companies are typically also required to disclose more routine occurrences like a change in directors on the company board or a change in the registered office address.

One of the contentious issues is the reporting of a company’s petroleum reserves, and efforts have been made to standardise this around the world. Different rules have been adopted in different jurisdictions, including guidelines on how reserves should be calculated and who is authorised to sign off on the calculations. These rules are designed to give investors a degree of confidence in the information they receive in the company’s reports. Unfortunately, the rules are not identical in all jurisdictions, leading to slight differences and reporting complexities for companies with listings in multiple jurisdictions.

For listed resources (including petroleum) companies, there are a number of other regular mandatory reports, including quarterly exploration, development and production reports, and half-yearly and annual financial reports (which must be audited).

When drilling wells, smaller petroleum exploration companies will also need to submit regular drilling reports to meet their continuous disclosure obligations. These drilling reports usually include details such as well name, permit location and position in relation to previous wells (if any), other fields and facilities. In addition, the report should contain the time and date, any hydrocarbon indications or test results, the depth of the well and particulars of the company’s interests in the consortium.

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Drilling reports

There are some basic parameters contained in drilling reports that are useful indicators of the well outcome.

Type of test

A drill stem test will usually give more information about a potential reservoir than the small samples obtained in repeat formation tests.

Flow rate

A strong flow indicates good permeability and good reservoir drive mechanism, but it can be qualified by other factors during the test.

Some wells may have a very strong initial flow rate, but quickly decline if the reservoir is small. So the duration of the test is important. If it is short there may not be enough time to indicate whether the flow rate will decline and how long it will take to stabilise at a certain rate.

In other cases, some horizons may not be very strong-flowing, perhaps because the formations have been damaged during drilling. That doesn’t necessarily mean the reservoir is not commercial. Explorers may be able to make a viable development using different drilling techniques.

Some reports give total or combined flow rates from several reservoir horizons which can be misleading when trying to draw conclusions about the size and potential of the find.

Choke size

If the reservoir pressure is high, an open hole test (one where casing is not used) or a large choke size will allow a large flow, whereas a small choke size will restrict flow from the same reservoir.

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Fluid recovery

If the flow contains water, it can mean the test zone is at or near the oil/ water contact. This may indicate a thin reservoir pay if the test has been made at the top of the formation.

Condensate values recorded with a gas flow are usually an enhancement of the commercial prospects of the find.

Interval tested

If the test is over a thick horizon and it is all pay, a good flow can indicate a sizeable reservoir.

Pressure build-up

Some tests are run for a time, stopped for a while and then resumed. If the flow during the second test is as strong as the first it indicates there is rapid pressure build-up and a strong reservoir drive. If the second flow is not as strong it can mean there is a slow pressure build-up and indicate the reservoir zone is thin or the drive mechanism is weak.

Report assessment

All the above parameters need to be looked at together when assessing a well result. No single factor can pronounce or dismiss viability. In addition, most discoveries need at least one and probably two or three appraisal wells before an accurate commercial assessment can be made. Good results in a wildcat do not necessarily mean a commercial field has been found.

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