At our request, BGE has calculated indicative tariffs for a number of different scenarios. For each scenario, the figures comprise
Indicative entry and exit charges (both capacity and commodity) calculated in line with our recommendations as described in this report. The tables below report entry charges for each entry point, and the postalised exit charge. The capacity and commodity charges are calculated for the years 2000, 2005 and 2008. To enable easy comparison, the tables then calculate from the capacity and commodity charges the average charge paid by a 67% load factor user, and by a 90% load factor user, for gas from each entry point.
Indicative hypothetical entry and zonal exit charges (again both capacity and commodity, for the same set of years). The purpose of calculating zonal exit charges is as an input into the calculation of the PSL. The method used by BGE to calculate the PSL is described below. The tables give indicative PSL values, and charges for 67% and 90% load factor users in the Dublin area.
BGE wishes to highlight the fact that the tariff calculations involve forecasts over a long period (out to 2025), and that there is inevitably a high degree of uncertainty around projections over this period.
Scenarios
We asked BGE to consider seven scenarios, as described in Table A2 below.
The scenarios involve variations in three sensitivities
· Gas demand scenario: scenarios 1 to 3 assume the Gas World B demand scenario from the Gas 2025 report, while scenarios 4 to 7 assume the Conventional Wisdom demand scenario from that report.
· West Coast gas: scenarios 1, 2, 4, 5 and 6 assume that the Corrib field is developed. The profile of volumes assumed to flow from Corrib is shown in the graph below.
· Additional West Coast gas: scenarios 1 and 4 assume that additional West Coast gas development follows on after the Corrib field enters production. The profile of volumes assumed is shown in the graph below.
In addition, scenario 6 assumes that BGE sizes its new infrastructure (onshore and offshore) based on the Gas World B demand scenario, but the actual realised demand scenario is the Conventional Wisdom one.
Note: For avoidance of doubt, the Corrib profile illustrated in this example is an internal BGE assumption and does not represent the position of the Corrib co-venturers.
Zonal Charges Methodology
The BGE system was allocated into six zones (see map):
· Dublin
· North-East
· Cork
· Limerick
· South-East
· Galway
Assets related to transporting gas and projected additions within these zones are directly attributable to the zone. Projected additions were allocated to the appropriate zone. The Gas 2025 study projected demand for each of these zones. A zonal tariff was calculated for each zone from this data.[18]
Each of the areas form the following proportion of revenue (in Present Value terms) to the period to 2025 under Gas World B:
· Dublin 16%
· North-East 2%
· Cork 9%
· Limerick 3%
· South-East 3%
· Galway 1%
· Shared 65%
Shared Costs were taken to comprise:
· Existing assets forming part of the main infrastructure (primarily Cork-Dublin)
· General assets such as land & buildings and equipment.
· Operating Costs, except those relating to the Entry Points
· Ring Main infrastructure
These costs were then allocated on a distance-related basis in the following manner:
1. Peak day flows were estimated for each route on the system for each year, i.e. from each Entry point to each Exit point.
2. The distance travelled on the shared infrastructure for each route was calculated.
3. The total distance travelled by gas on the peak day of each year was calculated (distance in km x millions of peak day therms).
4. A distance-related levelised peak day charge per km was calculated using the shared costs and total km travelled.
5. The distance-related peak day charge was allocated to each zone based on the distance travelled by gas used in that zone each year. This gave a total revenue requirement for shared costs for each zone.
6. The NPV of the revenue requirement for shared costs was added to the NPV of the revenue requirement of the assets in the zone to arrive at the NPV of the total revenue requirement for the zone.
7. The NPV of the revenue requirement and projected usage for each zone was then used to determine the appropriate tariffs for the zone.
Public Service Levy
As discussed above, a cost-reflective tariff is determined for each zone. A postalised tariff for the onshore system is calculated by taking the revenue requirement of the onshore system and the projected usage of the system. The public service levy is the difference between the postalised charge and the zonal charge.
The figures below illustrate the PSL paid in different locations, and for different sources of gas, in the year 2005, assuming a 67% load factor. The tables on the subsequent pages provide indicative tariffs for the different scenarios described above.
Cost Onshore IC1 Total
reflective PSL Charge Charge Charge
Scenario 2, IC1 user in Dublin
p per peak day kWh 6.31 8.29 14.59 22.98 37.57
p per kWh 0.0031 0.0039 0.0069 0.0102 0.0171
average charges p/kWh 0.0289 0.0378 0.0665 0.1042 0.1708
Scenario 2, IC1 user in South-East
p per peak day kWh 37.82 (23.22) 14.59 22.98 37.57
p per kWh 0.0207 (0.0138) 0.0069 0.0102 0.0171
average charges p/kWh 0.1754 (0.1087) 0.0665 0.1042 0.1708
Scenario 2, Corrib user in Dublin
p per peak day kWh 6.31 8.29 14.59 14.36 28.95
p per kWh 0.0031 0.0039 0.0069 0.0052 0.0121
average charges p/kWh 0.0289 0.0378 0.0665 0.0639 0.1306
Scenario 2, Corrib user in South-East
p per peak day kWh 37.82 (23.22) 14.59 14.36 28.95
p per kWh 0.0207 (0.0138) 0.0069 0.0052 0.0121
average charges p/kWh 0.1754 (0.1087) 0.0665 0.0639 0.1306
[1] Bord Gais/Arthur Anderson, Review of Tariff Structure for access to the Natural Gas Network, ¶¶ 6.9 and 6.29.
[3] NERA/Arup/Brown & Root, Financial and Technical Review of Proposed Changes for Access to the Irish Gas Transmission System, (June 1999), Table 6.2.
[4] Statement of Policy, 88 FERC 61,227, September 15, 1999, p. 25.
[5] There are exceptions to this incremental pricing policy, such as in cases of inexpensive expansions that is made possible because of earlier costly construction, where a pipeline has vintages of capacity and if some customers have the right of first refusal to renew their expiring contracts. Customers could be allowed to renew their contracts at their original contract rate except when the incremental capacity is fully subscribed and there are competing bids for the existing customers’ capacity. In that case, the existing customer could be required to match the highest competing bid up to a maximum price set at either an incremental rate or a rolled-in rate in which costs for expansions are accumulated to yield an average expansion price. Foster Report No. 2251, September 16, 1999, p. 3 or Statement of Policy, 88 FERC 61,227, September 15, 1999, p. 20.
[6] Statement of Policy, 88 FERC 61,227, September 15, 1999, p. 21.
[7] However, the FERC did not clarify what constitutes “a new, previously unserved market”.
[8] See 26 April 2000 rehearing order in FERC Docket Nos. CP98-540, CP97-319 and CP97-315.
[9] All gas pipelines are categorized to be one of two groups of companies, Group 1 and Group 2. The size of the pipeline and the number of associated shippers generally determine the form of regulation or which group it belongs to; large pipelines belong to Group 1 and smaller pipelines belong to Group 2. The NEB requires ongoing financial monitoring for Group 1 pipelines and requires a lower level of regulatory monitoring for smaller pipelines, generally on a complaint basis.
[10] Application to NEB for Amendments to the IT and STFT Toll Schedules contained in TransCanada’s Gas Transportation Tariff, October 29, 1999. In its application, TransCanada requested for approval a minimum price for both the IT and STFT service that is equal to 0.65 times the 100 percent load factor daily equivalent of the FT toll for the relevant path or segment on the TransCanada system. This is a change from the current minimum price of 1.0 times the 100 percent load factor for STFT and 0.5 for IT. In addition, it is prepared to accept a cap on these prices of 1.25 time the FT toll during the November to March winter period, and 1.00 times the FT toll during the April to October summer period. TransCanada reasons that there is significant amount of excess capacity and moving the price below the total cost level provides benefits by allowing the pipeline to capture markets that would otherwise be entirely lost.
[11] Volumes are allocated to the firm service shippers according to each shipper’s contracted firm service volume, up to a maximum of 10 percent of each shipper’s contracted demand quantity.
[12] Reasons for Decision, Alliance Pipeline Project, National Energy Board, GH-3-97, November 1998, p. 81.
[13] The NEB rejected proposals that would have required a new pipeline to set aside a contingency fund to pay for under-utilisation of existing pipelines. Reason for Decision Alliance Pipeline Ltd. GH-3-97, November 1998, p. 36 and 39.
[14] Canadian interest in producer “netbacks” stems from the importance of the Canadian gas producing industry to its economy.
[15] If an applicant has negotiated its transportation service packages with shippers, and that no shipper objects to the proposed tariff and tolling method, then the NEB would approve the tariff. If however, objections emerge, then the NEB would evaluate each case individually.
[16] Guidelines for Negotiated Settlements of Traffic, Tolls, and Tariffs, National Energy Board, August 23, 1994.
[17] Reasons for Decision, Vector Pipeline Limited Partnership, NEB, March 1999, para. 260.
[18] One change was made from the Gas 2025 assumptions. Gas 2025 assumed that two-thirds of all new power stations would locate in Dublin and the remainder in Cork. However, a number of parties are looking at building power stations in the North-East, and it was considered appropriate to calculate the zonal charges assuming that one of these plants goes ahead