Select Committee on Trade and Industry Appendices to the Minutes of Evidence


Second supplementary memorandum by UK Offshore Operators Association Limited

  We thank you for the opportunity to give evidence to the Committee and for your letter of 19 November requesting more information about UKOOA's view of long term production from and reserves remaining in the UKCS. We have pleasure in responding to your letter. We are also attaching a note regarding the possible introduction of shorter balancing periods for the National Transmission System operated by Transco.


  The graphs of UKCS production which we have already sent to you are based on production data from operators, supplemented by analysis of exploration, prepared by Prof Alex Kemp from University of Aberdeen. The production data extend to 2040. For each of the production categories, the following table summarises the estimates of remaining reserves in the period 2001-40.

Field Category Remaining reserves boe
Sanctioned fields11.1 billion boe
Incremental projects1.7 billion boe
Probable developments2.2 billion boe
Possible developments5.9 billion boe
Exploration success2.6 billion boe
Total23.6 billion boe

  In arriving at the quoted reserve range of 28 to 36 billion boe, UKOOA makes provision for further contributions to reserves. This is to compensate for the conservatism in the above estimates which arises from the fact that these profiles do not assume any contribution from new technologies and/or lower costs.

Brown Fields

  In addition to the estimate of 23.6 billion boe above, we add the estimated potential remaining in existing fields, often referred to as Brown Field potential. This adds a further 4.4 billion boe in ultimate potential; work in PILOT suggests that a target of 2 billion boe is achievable in the near term. These reserves are not economic today and will require new technologies and lower costs to become commercial.

Additional Potential from Undiscovered Reserves

  Predicting the contribution from future exploration success is difficult, given the range of estimates for the remaining potential, assumptions of exploration activity and commercial success rates from drilling. DTI estimates indicate a wide range of undiscovered oil and gas potential, from 4 billion to 30 billion boe. UKOOA does not share DTI's view of the magnitude of the potential, our comparable estimates for undiscovered reserves being from 5 billion to 13 billion boe.

  The production graph, attached in our letter of 30 October assumes a modest exploration contribution of 2.6 billion boe (in the period to 2020), leaving between 2.5 to 10.5 billion in yet-to-be-drilled prospects. For the UKCS to realise the high end of the yet-to-find potential, the rate of exploration drilling and the associated success rate would need to be significantly greater than the achievements of recent years (see chart above). UKOOA does not believe that sustained increases in exploration and appraisal activity, or success, are likely.

  The table below summaries the complete reconciliation of UKOOA's reserves position:

Billion bbls oil equivalent
CategoryReserves from 2001
Sub total23.5

Brown fields
2 to 4
Remaining Yet to Find2.5 to 10.5
Grand total28 to 36

Changes since 1995

  The reserve estimates from any basin are never static and therefore we would expect revisions as more data become available from seismic, drilling and production. With continual improvements in technology the trends in basin estimates are generally positive. To this extent, it is not surprising that UKCS remaining reserves have remained more or less unchanged, year on year, despite high production over the last six years. Indeed, this is a global phenomenon; global proven oil reserves at 1000 billion bbls are now 59 per cent higher than 20 years ago, despite the consumption of circa 500 billion bbls over the same period. For the UKCS however, it has now matured to the point where it is unlikely that the steady picture of remaining reserves, seen over the last six years, can be maintained. We envisage that estimates of remaining basin potential, whilst expressed as a range, will now be on a downward trend.


  UKOOA is currently updating the activity survey on which the production forecasts are based. These indicate that the significant increase in gas production predicted last year is now unlikely to happen. Several projects have been delayed and some downward revision in gas reserves has also occurred. It is more likely that UKCS gas production will remain flat for next four to five years, before decline sets in. With this anticipated decline in gas production, it is increasingly unlikely that UK demand will act as a constraint on the supply side. Changes in demand will translate into differing requirements for gas imports. UKOOA does not make predictions of gas demand—this is best left to other experts in the field—though we would not anticipate demand declining. It seems most likely to continue to rise.

  We enclose, for the Committee's information and in support of our statements, a leaflet prepared by Wood Mackenzie regarding their recent publication "Running Short of Gas?" (Horizons, energy issue 1, November 2001).


  It is true that forecasts of UKCS production have generally proved to be pessimistic, so it is legitimate to be sceptical about any such future forecast. However, the arithmetic demonstrates that it will be increasingly difficult to defy a significant production decline by 2010. Annual production is currently running at some 1.6 billion boe, whereas the volume of new discoveries and new developments per annum is much lower than this. With the average size of new discoveries on the UKCS of some 30 million boe, a very large number of commercial discoveries has to be made to replace current production. The aggregate volume of commercial discoveries in recent years falls a long way short of current production and, therefore, a sharp decline from the current, high production is inevitable by 2010. We agree with the consensus view of most forecasts of UKCS production that by 2010 the UK will be a net importer of both oil and gas. As you may be aware, PILOT has established a vision for 2010 which aims to deliver UKCS production of three million boepd. This is regarded as a challenging target, as most projections to 2010 fall short of three million boepd. The industry is confident that the target can be delivered, though many challenges remain. Even if this target is met, it will represent a 33 per cent decline in production from the peak experienced over the last couple of years.

29 November 2001




  The UK gas system currently balances on a 24 hour period (ie system inputs & outputs must be matched over 24 hours). The system operator (Transco) ensures that shippers' nominations which put gas into the National Transmission System (NTS) are balanced by offtakes from the system by shippers' customers. The 24 hourly system means that shippers usually flow at a 1/24th rate; however the key benefit of the existing system is that it has usually allowed producers to manage short outages or reduced flows offshore, either by "catching up" the quantities "lost" by the end of the day or via substitution (agreements between producers to cover one another's shortfall) without financial penalty and ensuring that their customers (the Shippers) have a smooth, uninterrupted flow of gas.

  There are occasions when there are discrepancies between shippers' nominations to Transco and physical gas flowing into the system and, consequently, Transco has to balance the system, which can be costly. The balancing costs are than smeared back on to all shippers. In order to resolve the perceived problem. OFGEM has proposed hourly balancing. The industry has expressed concern that imposing hourly balancing would have a significant impact on the upstream sector. UKOOA has raised these concerns with OFGEM, the DTI, as well as through PILOT.


Why is a change needed?

  To date no one has actually defined what the exact problem is which needs to be resolved. Until the issue is clearly defined and understood, it does not seem wise to us to look for solutions. We were advised that OFGEM had requested such a definition from Transco some six months ago. We have yet to see the result of this and, until we do, it is extremely difficult to know what, if anything, should be done. The cure may be worse than the alleged disease. UKOOA believes that a cost benefit analysis of the proposal would show that huge costs will be incurred with little benefit for the consumer or either sector of the gas market. Last year the total cost of Transco's actions to balance the market was £13 million, a tiny fraction of the value of the gas shipped through the NTS. This was shared 25/75 between Transco and Shippers.


  Hourly balancing will lead to significantly increased costs for both downstream and upstream UK gas market players. Whilst the proposals are aimed at the downstream, shorter balancing will inevitably have significant impact upstream. The issue of downstream regulation impacting on the upstream sector is a concern that we have raised in the past and was the reason that UKOOA sought to introduce an amendment to the Utilities Act to ensure that the regulator had a duty to look at the impact of regulation on all energy sectors in order to ensure "a diverse and viable long-term energy supply".

  A brief outline of the main areas of concern are:

    —  Metering costs: shorter balancing will necessitate increased metering offshore, with the need for far greater accuracy and timeliness of information than currently exists. As the need for greater accuracy increases, so will the costs of those meters and of installing them. A further source of high cost would be the data transmission system for these extra meters: would producers be expected to lay fibre-optic cables from platforms [the answer is likely to be "yes"]. In order to mitigate the financial risks of a shorter balancing period it is inevitable that both producers and terminals would be required to install additional metering. Currently the industry estimates over 100 platforms would require new meters indicating a cost to the industry of some £200 million. There will also be the costs of upgrading the terminals which will be borne by offshore producers.

    —  Allocation systems & IT: The move towards shorter balancing periods would require that new IT systems, such as allocation, attribution and scheduling, be developed and introduced. Many older platforms would need substantial IT investment in order to cope with the increased hardware and data demands. Finally, terminals would need IT upgrades. As shorter balancing periods would mean a huge increase in data volumes from offshore and terminals, it is likely that IT systems serving the upstream could potentially be very costly. [Changes to the CATS and SEAL systems are likely to be less onerous because they were both designed to provide within day information on gas ownership—none the less changes will be required even to these systems since they provide for within day catch-up if the nominations for a particular period are not met].


  Flexibility upstream is delivered via a combination of increasing or decreasing the flows from wells, offshore facilities and production trains—all of these have their own specific constraints in terms of minimum and maximum allowable flow rates in gas, liquids impurity removal, the response time and behaviour of plant and machinery, etc. There are a number of technical & operational difficulties in providing such flexibility (eg starting up wells or adjusting flows), meaning that attempting to increase flexibility, especially over a shorter time period, is likely to lead to less reliability or the delivery of non-spec gas (with increased likelihood of flaring). In order to increase flexibility upstream, significant additional investment in offshore capacity will have to be made; however this will also mean less utilisation of offshore facilities and therefore of capital employed.

    —  Role of substitution agreements: the current system allows small outages or reduced flows to be covered via substitution arrangements and catch up of end-of-day flows. This is efficient for both upstream and downstream: producers can cover unexpected production problems and shippers/customers receive an uninterrupted flow of gas. However, with a shorter balancing period the ability to catch up or to substitute is considerably curtailed; it is unlikely that another platform will be able to increase production to cover its own flows and substitution flows within a few hours (it is far easier to do this over a longer 24 hour period).


  UKOOA believes that all of the above could ultimately result in less gas reaching the market and as a consequence contribute to increased price volatility. The additional cost of metering & IT and, potentially, reduced offshore revenues may well result in marginal fields not being developed, and existing older fields being shut prematurely. Shorter balancing periods are also likely to have impact on the competitiveness of the UKCS: with higher costs and increased risk, the attractiveness of the UK for new entrants and smaller players will be diminished (regulatory risk in the UK is an increasing concern within the industry). The introduction of shorter balancing periods would negate much of the successful efforts to date of Pilot and other industry initiatives to reduce the cost base of upstream oil and gas. At a time when the industry is focused on initiatives to increase upstream productivity through the reduction of operating costs a move to a regime which will increase costs runs counter to the desired objective.

    —  Cost of renegotiating existing contracts: existing contracts are based upon an end of day quantity which is flowed over 24 hours. Shorter balancing periods will mean that contracts must be reopened and renegotiated; this is likely to be both time consuming and expensive in terms of internal manpower and legal resources. The complex renegotiating of contracts could incur costs of between £100,000 to £250,000 per contract.

    —  Operational Costs: The cost of operating the Terminal and Field allocation systems will increase considerably as significantly more personnel will be required to operate the systems and disseminate information. There will also be cost increases associated with supporting the revised metering and data transfer systems. The introduction of these costs will create a higher barrier to entry and will discourage participation by small players. (Similarly in the downstream there will be significantly increased operating costs for Transco and other downstream participants associated with handling the additional data flow and monitoring inputs, offtakes and line pack for each individual balancing period). We also believe that impact will be felt by parties such as the Claims Validation Agency (CVSL) who will have to deal with 24 times the quantity of data they currently receive and process it in real time; not only will costs be significant in such a move but the logistics are likely to be very difficult.


29 November 2001

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