Notes From The Field - An English Law Perspective On The Oil & Gas Market
The ecological credentials and energy efficiencies of natural gas as a feedstock for power generation, in comparison with combusting coal or fuel oil, are well known. In the United Kingdom the anticipated boom in shale gas production has been earmarked by several commentators as a feedstock for power generation, in preference to reliance on the vagaries of imported gas. The production characteristics of shale gas will require a different means of contracting for the supply of gas for power generation, however, in comparison with supplies from conventional gas sources.
Because of a combination of delays in the new-build nuclear programme, the forced retirement of 'dirty' fossil-fuel burning power plants and the lack of predictable reliability around power generated from renewable energy sources, the UK is increasingly looking towards natural gas (in any form) as a feedstock for power generation. As such, a decline in the rate of indigenous natural gas production from conventional offshore gas fields has led to increased reliance on gas imported from abroad in the form of LNG, and with that comes the exposure of the UK to the need to compete in global gas markets and so to the associated risks of uncertainty of gas supply. Consequently, the prospect of being able to rely on significant volumes of proximate and readily available domestic shale gas as a feedstock for power generation has an obvious appeal.
This article examines how a conventional gas sales agreement (GSA) will need to be modified to reflect the nuances of such a project, assuming that the parties to the shale gas project have by their development efforts liberated sufficient volumes of gas to constitute commercial quantities that are available for sale or supply.
The content and the effect of a gas supply agreement (GSA) in a conventional gas to power project are well understood. The position will necessarily be different however where the gas to be sold comes from an unconventional source such as a shale gas deposit. In this context, the content of a typical GSA (indeed, of the whole project structure) will need to be reconfigured to reflect the peculiarities of a direct feed of shale gas as a feedstock for power generation in a number of ways.
Much of how the GSA is crafted will also depend on the manner in which the gas buyer (which is a power generator) has contracted to sell the electricity produced from the combustion of the gas. Where the resultant electricity is not sold into a price-competitive pool on a merchant basis then the gas buyer could have a long-term contract, to sell the resultant electricity to an electricity buyer, under some form of power purchase agreement (PPA).1 The challenge of the gas buyer will be to harmonise the terms of the GSA and the PPA as far as possible, in order to eliminate mis-match risk (relating, for example, to the scheduling of energy quantities and penalties for non-performance) between the two documents. It might not however be possible to contain all of the risks within the GSA.
Depletion or supply contracting
At the outset, in terms of structural design, the GSA might be distinguished on the basis of whether it is a depletion contract or a supply contract. Understanding the popularly-recited differences between these two formulations is helpful in appreciating that in practice the distinction is rarely so clear.
In a depletion contract the seller dedicates a nominated gas field to the buyer and will undertake to produce for sale to the buyer all or at least a significant defined percentage of the reserves of gas in that field.
Several features characterise a depletion contract:
- Sources of supply – a nominated gas field will be dedicated by the seller for the exclusive sale of gas to the buyer. The buyer could see this dedication as the quid pro quo for any take and pay or take or pay commitment (see below) which enables the field to be developed and consequently the buyer will rely on the dedication mechanism as a means of preventing other buyers from benefiting from the seller's development.
- Gas delivery profile – because the GSA is for the sale and purchase of whatever gas quantities are contained within the dedicated gas field, the annual contract quantity (see below) for each year is likely to vary in accordance with the profile for the production of gas from the dedicated gas field over its lifetime. The annual rate of gas production will typically ramp up at the start of the GSA as the gas field comes on-stream, achieve a plateau level of production as the gas field performs at its optimum rate and eventually ramp down as the reserves of gas in the dedicated gas field begin to deplete.
- Reservoir force majeure – under a depletion contract the seller's performance will depend upon the continuing physical productivity of the gas reservoirs in the dedicated gas field. The seller will seek to protect itself from bearing the risk of non-performance of the reservoirs through securing in the GSA the right to claim force majeure relief (see below) for reservoir failure.
- Economic termination – the seller could require a right to terminate the GSA where it is no longer economic for the seller to continue to produce gas from the dedicated gas field, to protect the seller from being burdened with an economically unproductive project. What is and is not 'economic' might be left undefined, although to do so could be a recipe for dispute. The clearest solution is to include an explicit definition in the GSA.
In a supply contract, on the other hand, the gas is treated as a fungible commodity and the seller commits to deliver specified quantities of that gas to the buyer over a given period without linkage to a particular gas field's production profile.
Several features characterise a supply contract:
- Sources of supply – the sources of supply of gas need not be specifically identified nor dedicated to the buyer and in practice the seller could deliver gas from a portfolio of gas fields and facilities and through other contractual rights, and could make good any deficiencies in a particular field by delivering gas from alternative fields, or from gas sourced from third-party trades. Supply contracts are particularly suited to where the seller has multiple gas production and transportation facilities and/or contract entitlements and is able to facilitate the delivery of gas from diverse sources.
- Gas delivery profile – the annual contract quantity (see below) will usually be an absolute quantity of gas to be delivered at a consistent rate during the basic term of the GSA. There might be a commercially-driven ramp up at the start and/or ramp down at the end of the term of the GSA in order to fit with the buyer's requirements (e.g., a ramp up as the buyer's gas demand is established and a ramp down as the buyer brings on other sources of supply of gas) but these modulations of contract quantities will not be driven by the productivity of a particular gas field, as is the case for a depletion contract.
- Reservoir force majeure – this risk will typically remain with the seller in that the seller will be less able to claim complete force majeure relief (see below) in respect of the non-performance of the multiple gas fields or other interests which underpin the performance of the GSA.
- Economic termination – the seller is typically not entitled to exercise an economic termination right in respect of the GSA, since the seller could in theory switch gas production to other production sources from the seller's portfolio in order to continue to meet the needs of the GSA.
In practice it is often the case that a particular GSA will demonstrate something of a combination of the characteristics of a depletion contract and a supply contract. Where a particular GSA ends up will be the product of negotiation between the buyer and the seller.
For a sale of shale gas to a power generator buyer the seller could dedicate a defined shale gas deposit, in the manner of a depletion contract. The inevitable variability in the rates of production of gas from a shale gas deposit is a fact which has to be addressed in the GSA however. The somewhat spiky profile of the production of gas from a shale gas deposit makes it difficult to engineer a conventional ramp up, plateau and ramp down gas delivery profile.
This could result in the support of the dedicated shale gas deposit by substitute sources of shale gas from other deposits, thereby giving the buyer access to a quasi-portfolio approach in the manner of a supply contract. Such an approach favours a portfolio producer of shale gas, which draws gas from a number of shale gas deposits.
This portfolio production model could be further modified to see shale gas production from a number of producers routed through a nominated aggregator-seller in order to provide the certainty of gas supply which the buyer might require:
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As a further development of the idea of the sale of shale gas from a multi-source portfolio, the seller could have access to a mixture of conventional and unconventional gas supply sources, and could supplement the sale of shale gas through additional supply from conventional gas sources (assuming that the chemical compositions of the different gas sources (see below) are consistent). This would give the buyer the benefit of a hybrid portfolio.
The seller should properly not be able to claim a right to terminate the GSA on the grounds that the production of shale gas has become 'uneconomic' at any particular time. There will always be times in the exploitation of a particular shale gas deposit where that would be the case because of the very nature of the shale gas deposit's production profile.
If there is to be an economic termination right in the GSA in the seller's favour then it will need to be set at a level which reflects a sustained period of uneconomic performance and/or more macro-economic factors. The portfolio sales structure lessens the risk of gas production from an individual deposit being uneconomic to the extent it is untenable to the seller.
Transportation and the delivery point
For the sake of illustration, and with deliberate over-simplification, this article assumes that a sale of gas is made directly from a shale gas deposit for delivery (by pipeline) to a nominated power plant:
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The delivery point is the point at which gas transfers from the seller to the buyer and is the pivotal point of connection between upstream and downstream interests. The delivery point will usually be defined in the GSA as a precise geographical location and within that location as a particular point of the interface between the seller's gas production facilities and the buyer's gas reception facilities (subject also to imposing within that structure the addition of any intermediate gas transportation infrastructure).
This article also assumes that the parties to the GSA have agreed to effect a physical delivery of gas, rather than a notional gas delivery (which would, for example, be effected through entering into a National Balancing Point (NBP) trade).2
In further support of the portfolio sales model suggested above, the exploitation of a shale gas deposit could see the resultant gas gathered by a series of pipelines over a relatively wide geographic area and combined into a single export pipeline which the seller has built as a consolidated point of exit from several shale gas deposits. Thus, it may be that the delivery point is the point of connection of the seller's shale gas production facilities to an export pipeline which then takes the consolidated shale gas flow away from those facilities and to the buyer’s power plant. This would require the construction of a gas gathering system across a series of shale gas deposits, which could lend itself to a joint development programme between multiple shale gas producers (see Part 1 of this article).
Alternatively, the seller could assume responsibility for delivering the produced shale gas volumes to the UK gas pipeline transmission system, the National Transmission System (NTS).3 The delivery point would be the point of entry into the NTS. The buyer would assume responsibility as a shipper for the transportation of gas through the NTS and would, at a separate offtake point from the NTS, take delivery into the buyer's power plant of a quantity of gas equivalent to the quantity of gas delivered by the seller into the NTS at the delivery point:
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The delivery of gas into the NTS by the seller represents the buyer’s right to take delivery of a matching quantity of gas at a separate offtake point (effectively a form of drawing right). Consequently the NTS could be imbalanced by the taking of delivery by the buyer of a quantity of gas which is lesser or greater than the quantity of gas which was input by the seller. If this is the case then the GSA should recognise the contractual implications for both parties of system imbalance resulting from contractual mis-performance.
As a further alternative, the GSA could be structured such that the seller is responsible for securing the necessary capacity in the NTS, and so effects a delivered sale directly to the buyer's power plant, which relieves the buyer of the necessity to be concerned with administering the gas transportation function. The seller would therefore require to be registered as a shipper within the NTS:
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The UK government is generally not keen to encourage a proliferation of new pipelines, and wherever possible shale gas production will be routed to tie into the NTS at the earliest opportunity. It is unlikely that a new pipeline network will be constructed to cover the distance between a shale gas deposit and a power plant where the NTS could be accessed instead. Much depends of course on where the shale gas deposit is relative to the intended power plant; if the NTS is not proximate then new pipeline infrastructure becomes inevitable (which in turn will require compliance with the applicable regulatory regime in the UK for new pipeline development).
An early task that ordinarily applies to the buyer and the seller is to determine the overall quantity of gas which is to be sold under the GSA, the contract quantity. The contract quantity is often applied to represent the maximum quantity of gas which the seller is obliged to deliver to the buyer over the lifetime of the GSA, although this can be a difficult matter to estimate in advance (and particularly so in the case of shale gas, given the variability of production) and the actual quantities of delivered gas could well be lesser than or greater than the defined contract quantity.
The seller will calculate the contract quantity which it is prepared to offer by reference to the quantity of economically-recoverable reserves of shale gas which it estimates it has (or will have depending on future exploration programmes) access to through production, and also by reference to contracted-for volumes of gas which it can access (where a portfolio sales model is applied). The buyer will calculate the contract quantity which it requires for its commercial purposes (which in turn will be conditioned by the PPA). A matching of how much gas the seller has versus how much gas the buyer needs will determine the definition of the contract quantity in the GSA.
It is not the case that every GSA will recite a contract quantity. For the production of shale gas the production profile is inherently difficult to estimate at the outset of a project, more so than is the case for a conventional gas production project. Thus, a contract quantity could be a particular rarity in a GSA for the delivery of shale gas, and shorter-term measures of gas quantities could be the norm.
In a sale of gas to a power generator, that buyer will require sufficient flexibility in the gas quantity determinations under the GSA to match the operational needs of the power plant. A more relevant measure of gas quantities will be by reference to daily gas flows.
The seller will allow the buyer in respect of each day to nominate for delivery a maximum quantity of gas equal to a defined daily contract quantity (the DCQ) and may also allow the nomination of a further percentage of the DCQ (the swing factor). The swing factor represents the peak loading of gas that the buyer can access in order to meet spikes in its gas demand and consequently a buyer will prefer to have as much swing as possible, since the swing factor is intended to match the buyer's load factor. This is of particular importance to a power generator buyer, where volatility in the demand for power at peak load times will translate into a corresponding need to increase the rate of gas delivery.
The swing factor and the underlying DCQ together give the maximum daily contract quantity (or MDCQ) in respect of a day and the quantity of gas which the buyer can require for delivery in a day, up to the MDCQ, equates to the delivery capacity which the seller will be required to maintain within its gas production and transportation facilities.
The seller must ensure that the physical capabilities of its gas production and transportation facilities can accommodate the daily delivery of gas at the MDCQ. This may require the seller to incur the expense of building additional delivery capacity into its gas production and transportation facilities which might periodically be redundant, but the seller will typically factor these redundancy costs into the contract price (see below). For this reason the buyer should assess whether it really needs the flexibility afforded by the swing factor or whether the buyer is better placed to provide or procure that flexibility itself from elsewhere.
Beyond the swing factor, the buyer might also call for the delivery of gas quantities in excess of the MDCQ from time to time. In these circumstances it is customary for the GSA to say that the seller will in response to a request by the buyer use reasonable endeavours to deliver such quantities of excess gas, which will, if delivered, then typically be paid for by the buyer at a premium to the contract price.
In the commercialisation of a shale gas deposit the seller will need to make a careful assessment of whether it is able to meet the buyer's demands for the MDCQ and for excess gas opportunities. This in turn will drive the seller's decision to develop a shale gas deposit as a standalone interest or as part of a wider portfolio sales project.
Nominations and variations
Ordinarily the buyer will nominate the quantity of gas that it requires to have delivered to it in respect of each day, through a defined nomination mechanism in the GSA.
Nominations for the delivery of gas may be made for calorific values or for units of volume, depending upon how the GSA expresses gas quantities. For a power generator buyer the calorific value of the gas will be significantly more important than the volume of the gas.4
The buyer should ensure that its nominations fit with its requirements for gas and with the commitments to which it is subject under any PPA. The seller should ensure that the nominations timetable is sufficient to give the seller adequate time to produce gas and to schedule the required gas deliveries and fits with the scheduling requirements of the pipeline or other facilities which the seller may be using to transport gas to the agreed delivery point.
Alternatively, it may be that the seller will declare the availability of gas to the buyer and the buyer will then be obliged to take delivery of that gas whenever it is available. This seller's nomination regime is less typical in the context of conventional gas sales but could be applied to the production of shale gas, where the production of gas has a variable profile and predictability of output could be difficult to secure.
It could also be the case with the development of a shale gas deposit that the seller will be able to set a wide gas production pattern and within that pattern a conventional buyer's nomination regime can be accommodated. This in turn drives the seller's decision to develop a shale gas deposit as a standalone interest or as part of a wider portfolio.
Nominations will be given by the buyer at least once in respect of each day. The buyer may require a frequency of nomination greater than daily where its gas delivery requirements call for greater flexibility (particularly so where the gas is being combusted in a power plant) and so, for example, a 24-hour period could be split up into a series of equal and separate nomination periods, in respect of which the buyer will give a series of nominations. Typically the buyer will identify its daily peak load requirements and will try to ensure that the definition of a day, and the sequencing of the nomination periods within that day, is such that the nomination periods do not straddle the identified peak load periods for the power plant.
The flexibility available to the buyer in giving and in varying its nominations will be constrained by the physical limitations of the seller's gas production and transportation facilities. It may be that only a zero or a minimum-level nomination can be entertained where the buyer is giving a downward variation and there may be limitations on the seller's ability to ramp up gas production which will condition the seller's ability to accommodate the buyer's requirement for an upward variation.
From all of the foregoing it will be apparent that it could be difficult to correspond a shale gas production profile with the load requirements of a gas-fired power plant. This is another reason why a portfolio sales model could be preferred, because of the greater delivery flexibility which it potentially gives the seller.
In the GSA the seller could reserve the right to interrupt the delivery of gas to the buyer, typically for a defined period of time and usually only upon a requisite period of notice being given to the buyer and often then only on a defined number of occasions in each year. Where this is the case the particular GSA would be described as interruptible.
Such a right of interruption is of commercial advantage to the seller where operational constraints prevent the seller from being able to deliver gas to the buyer, to be applied particularly where there is a likely prolonged disruption to the anticipated rate of shale gas production for which the seller would require some relief (where, for whatever reason, force majeure relief (see below) would not be forthcoming). Interruption rights could be used by a seller to obviate the vagaries of shale gas production (although the introduction of a portfolio sales model should mitigate the need for the seller to rely upon an interruption right).
From the buyer's perspective a right of interruption would only be acceptable where the buyer is able to switch to an alternative source of gas or other fuel supply (if the buyer’s power plant has dual fuel capability) or is able to manage without gas for the duration of the interruption.
To give the buyer an economic incentive to accept a GSA with a right of interruption in favour of the seller either the overall contract price (see below) might be lower or where the seller exercises the interruption right the buyer might be compensated by the application of a price discount in respect of equivalent following quantities of gas which are delivered by the seller.
Take or pay
Shale gas could be sold on a purely merchant basis to the buyer – when the seller has shale gas production available it will declare that shale gas to be available (particularly where a seller's nomination regime applies – see above), the buyer will take delivery of it and will pay the seller the agreed contract price (see below) for the gas quantities which the buyer so takes delivery of.
This formulation could be insufficient for the seller however, because of the unpredictability of revenue due to flow from the buyer which it represents, and so the seller could require an economic model for the sale of gas which offers greater certainty of revenue income. This is particularly so if the seller is relying on third-party debt finance to develop its shale gas deposit, where the lenders would particularly require that greater certainty. Consequently, a sale of shale gas might be structured through a take or pay commitment so that the seller can better ensure constant revenue.
The seller could give the buyer an option on whether or not to take delivery of a defined quantity of gas (the take or pay quantity), on condition that the seller would require the buyer to make payment to the seller for all quantities of gas which would otherwise be delivered under the GSA. This creates an obligation in debt in the seller's favour and is in essence the take or pay payment. The buyer could have a subsequent right to recover the quantity of gas not requested for delivery by the buyer but in respect of which a payment has been made by the buyer, through the make up provisions in the GSA. The buyer's future right to lift make up gas in the recovery of take or pay payments could be difficult for the seller to satisfy, given the variable profile of shale gas production.
A typical take or pay commitment will operate and apply on an annual basis. This could be too rigid a denomination for the vagaries of shale gas production however, and so a daily take or pay commitment from the buyer (with within-year make up rights) could be agreed between the parties.
Where the buyer is selling the produced electricity under a PPA, that PPA could imply a similar take or pay right in favour of the power purchaser. The buyer will therefore be keen to ensure that, as far as possible, there is correspondence between the take or pay receipts it is due to receive under the PPA and the take or pay liabilities which it is exposed to under the GSA.
There might also be times when, in respect of a defined period of time, the buyer wishes to take delivery of more quantities of gas than is represented by the corresponding take or pay quantity. This incremental gas quantity could be carried forward as a credit against future take or pay commitments, allowing take or pay quantities to be reduced in later periods.
The challenge for the parties to the GSA is to ensure that the level of gas production from a shale gas deposit will be able to match the commitment and the flexibility which the take or pay, make up gas and carry forward gas provisions together are intended to deliver. Once again, the portfolio sales model presents advantages in this regard.
The contract price
The GSA will specify a price payable by the buyer to the seller for gas supplied under the GSA. That price could be fixed for the duration of the GSA, could be a base price which is subject to indexation over time against an agreed basket of escalation indicators, or could be set by reference to a defined gas market price (where a sufficient liquid gas market exists). In the latter case in the UK the gas price could be set by reference to the reported price of traded gas volumes at the NBP.
The agreed contract price represents what the buyer will pay – which will not always be as much as the seller would ideally like to be paid. The buyer could argue for a relative price reduction, in reflection of the perceived uncertainties associated with the production of shale gas (including the application of interruption rights). In contrast therefore, the sale of shale gas from a portfolio could go some way towards reducing those uncertainties and so towards eliminating the buyer’s claim for a price discount.
The price payable for gas under the GSA will also need to be referenced to the revenues due to the buyer from the sale of electricity under the PPA, since the buyer will be keen to eliminate any disparity.
The GSA will recite a specification for the quality of the gas to be delivered by the seller to the buyer at the agreed delivery point. The quality specification provisions in the GSA will address the required chemical composition, calorific value and temperature of the gas.
There is presently a paucity of data regarding the likely quality specification of shale gas deposits in the UK. The expectation is that shale gas will show similar compositional characteristics to conventional gas deposits (which also encourages the prospects of a portfolio sales model based on combining conventional and unconventional sources and the possibility of transporting shale gas through the NTS).
It may be that gas is delivered directly to the buyer in the same physical condition that it leaves the seller's shale gas deposit. The quality specification would therefore reflect the nature of this raw gas. Prior to the point of delivery to the buyer however the gas may be treated by the seller (possibly at the buyer's expense, to be reflected in a higher contract price) in order to remove impurities or to modify the calorific value.
The seller would prefer a widely drawn quality specification in order to maximise the deliverable quantities of gas and to minimise the possibility of a liability for delivering off-specification gas. The buyer on the other hand will require a specification which is consistent with the commercial requirements of the buyer (notably, gas within a specified calorific value range for combustion in the power plant).
Under the GSA, the freedom of the parties to negotiate the specification will be limited where the gas is to be transported to the delivery point through the NTS, since the applicable pipeline system rules (the Network Code) will apply a prescribed specification for application to all quantities of gas using the NTS for transportation.
The least troublesome construction for the sale of shale gas to a power generator buyer is that the seller will transport the produced gas to an NTS entry point (see figures 3 and 4 above), ensuring that the gas has a quality specification which is sufficient to meet the entry point requirements of the NTS. This eliminates the risk to the buyer of the gas being off-specification and unfit for combustion in the power plant, as long as the NTS quality specification is compatible with the power plant quality specification requirements.
If however the gas to power project is structured such that there is a direct pipeline from the shale gas deposit to the power plant, without the intervention of the NTS as a neutralising agent in respect of gas quality specifications, then the buyer is exposed to the risk of variations in the quality of the produced shale gas. This will require certain protections to be engineered in the GSA in favour of the buyer against its knowing or unknowing acceptance of off-specification gas into the power plant, and could oblige the seller to fund the costs of gas processing equipment so that the necessary quality specification is maintained.
In the simplest sense the GSA will be an agreement for the sale of gas and will not contain detailed provisions relating to any necessary facilities.
Where however new facilities are required to be built then the GSA (or a separate project development agreement) could contain detailed provisions relating specifically to the construction, installation, commissioning, operation and maintenance of those facilities.
The reasoning behind such a facilities obligation is that it imposes upon the party responsible to satisfy it an enforceable contractual commitment to ensure that the facilities which are critical to the performance of the gas project will be developed, made available and kept in place as necessary for the performance of the GSA. This obligation will help to better ensure the likelihood of success of the wider gas project because every necessary link in the supply chain will (hopefully) be complete when it needs to be.
A buyer that has committed to purchase gas from a shale gas deposit could have a keen interest in ensuring that the seller puts in place all of the necessary gas production, gathering, processing and transportation infrastructure, in order to bring greater certainty to the wider gas to power project (particularly where a portfolio sales model is adopted). Consequently, a facilities obligation could be a key component in a shale gas GSA.
Where it is agreed that a facilities obligation will be undertaken then several components will arise for consideration. The required facilities should be carefully defined in the GSA in order to prevent later disagreement between the parties about whether the facilities obligation has in fact been satisfied by the party required to do so. The GSA should define the extent of a party's obligations in respect of the required facilities. The timetable for the installation and commissioning of specified facilities should be based on defined interim and/or final dates for the obligations to be completed, such that the right of a party to seek the remedy of specific performance or even to terminate the GSA in respect of the failure of the other party to properly perform the obligations can be better applied. The GSA should also clearly define the test for completion and readiness in respect of specified facilities and how that test is to be satisfied.
Force majeure relief
The GSA will usually identify a series of events or circumstances which can legitimately be claimed by a party as force majeure, in order to afford relief to the affected party from a liability which would otherwise apply for a failure to perform contractual obligations.
Items that the parties typically have in mind when drafting force majeure provisions are natural catastrophes, although the concept of force majeure is often wider than events attributable solely to natural causes and the list of events will typically also include man-made interventions such as war, strikes or legislative interference.
The theme that is common to each of the above events or circumstances is that to be claimed as force majeure an event must be genuinely beyond the control of the affected party and it must prevent, impede or delay the affected party from performing the obligation in the GSA in respect of which relief is claimed from a liability for a failure to perform.
Since the primary obligation of the seller under the GSA is to deliver quantities of gas which meet the buyer's nominations and the gas quality specification, the seller's principal interest is in securing the availability of force majeure relief for liabilities under the GSA for gas delivery failure or for the delivery of off-specification gas. The somewhat spiky profile of the production of gas from a shale gas deposit could make it difficult for the seller to sustain a claim for force majeure in respect of disruptions to gas production because periodic reservoir failure (through depletion) is in essence an ongoing and inevitable feature of shale gas production. The use of a portfolio sales model could reduce instances of force majeure to be claimed by the seller because of the seller’s ability to modulate gas production across a wider set of facilities.
The buyer may also require the availability of relief from its take or pay commitments to be extended to apply to problems with the PPA, so that any event relating to power generation which impacts the ability to take delivery of gas will give reciprocal relief to the buyer. The seller may be unwilling however to accept unlimited downstream risk and may in the GSA seek to control the circumstances by which such relief may be afforded to the buyer.
Selling power rather than gas
On paper at least, the gas produced from the shale gas deposit could be piped directly to a power plant, for combustion and the production of electricity. The operational reality however is that gas production quantities and profiles from a single shale gas deposit will be insufficient to provide the base load of gas supply which a power plant requires. This insufficiency could be remedied in part by the aggregation of shale gas production from a number of different sources in a portfolio sale.
As an alternative to selling gas to a power producer, the shale gas producer could decide to build its own captive power generation facilities at the site and would instead export the produced electricity onto the grid for sale, assuming that the necessary grid connection can be secured.
Such a model has been used in the UK for the commercialisation of coal mine methane (CMM) and coal bed methane (CBM) deposits. CMM and CBM production is subject to periods of unavailability which makes it insufficient to serve as the sole base load source of gas supply to a conventional power plant. Key to the commercialisation of CMM and CBM has been onsite small and medium scale flexible power generation, and this technology could be applied also for the commercialisation of shale gas deposits.
In the UK reliance on localised, flexible power generation with fast reaction times has grown, particularly due to increased reliance on wind generation and the intermittency which is an inevitable consequence. Attractive premiums are paid for the supply and availability of such standby generation during times of peak power demand. The production of shale gas could be modulated such that the producer can optimise the use of shale gas and other sources of gas (or other fuel sources, if dual-fuel options can be structured) for power generation.
A further benefit of such small and medium scale flexible power generation is that, in comparison to a conventional power station, it can be made mobile and portable. When the gas production profile from a particular shale gas deposit has become such that it is no longer economically efficient to produce shale gas and to generate electricity, the producer could relocate the power generation equipment to another shale gas deposit (subject always of course to there being a grid connection and available entry capacity at the new location).
The aim of a shale gas project is to produce sufficient quantities of gas that can be sold at a sufficient profit. The GSA is the pivotal point of interface between the shale gas producer and the intended buyer of its shale gas production, and is the vehicle by which gas and money change hands.
What ought to go into a GSA is generally well understood by most industry participants but, like the JOA, some modification of the basic document will be essential in order to ensure the best chance of developing the shale gas project. The consolidation of shale gas production into a portfolio sales model (whether for the sale of shale gas alone or in combination with conventional gas sources) will have the capacity to re-shape the conventional parameters of the GSA.