Attachment 1
Calculation of ESB Power Generation
Revenue under the
Annual Bulk Power Agreement
TABLE OF CONTENTS
1.
INTRODUCTION
1
2.
OVERVIEW
3
3.
TREATEMENT OF PEAT PLANTS
4
4.
CONTROLLABLE COSTS
4
5.
MARKET DRIVEN COSTS AND REVENUES
6
6.
ALLOWED FUEL COSTS
7
7.
TREATMENT OF VARIATION IN TOTAL VOLUME
PRODUCTION
10
OTHER ISSUES
10
8.
APPENDIX 1 APPLICATION OF INTEREST
12
APPENDIX 2 DETERMINATION OF MONTHLY FUEL VALUES 13
2
APPENDIX 3 FIXED VARIABLE ELEMENTS OF FUEL
INDEXATION FORMULAE
21
APPENDIX 4 INFORMATION PROVISION
23
APPENDIX 5 NON RECURRING STATION COSTS
25
1.
Introduction and Summary
This paper set out the details of the transfer pricing mechanism between PG
and PES for the sale of output. The following points 1 to 14 summarise the
highlights of this bulk transfer arrangement.

This Agreement covers the sale of electricity from PG to PES for the
period from 1st January 2002 to 18th February 2005 inclusive. The
provision of other PG services to the market (e.g. Top Up, the Virtual IPP
scheme, Ancillary Services, System Support, Emergency Generation and
Capacity Margin) are not included in this Agreement. However PG’s
allowable revenue under this Agreement will be adjusted to take account
of revenues earned by PG through the provision of these services. PG’s
allowable revenue is calculated as PG’s total allowable costs less other
regulated revenues earned in the market.

Any deferred PG allowable revenues and interest thereon that is not being
recovered in any one year will be allowed to be recovered via the tariffs of
the following years.

Under Section 39 of the Electricity Regulation Act, 1999, (as amended by
the Sustainable Energy Act, 2002) the Minister shall by order direct the
Commission to impose Public Service Obligations on ESB and other
parties. This Order provides for the recovery of additional costs
associated with ESB’s peat fired stations. This Order will take effect on
January 1, 2003. PG’s allowable revenues have been amended to take
this into account.

All settlement shall take place at the Trading Point and all output,
demand and prices shall be determined at this point.

Subject to Clause 2, PG will recover from PES any additional charges
levied on PG associated with PG providing output to PES under this
Agreement.

PG’s allowable revenue has been set out on a €/MWh basis and shall
comprise both a controllable and a market driven component. This price
shall be profiled by time of day and season.

The fuel component makes up the largest part of the market driven costs.
The initial fuel component is compared to indexed outturn figures for
each month. Each month a revised fuel component is calculated.

This indexation process takes account of changes in a basket of specific
fuel indices. For the purposes of this Agreement, the weighting for each
fuel type included in the basket is calculated as expected output by fuel
type expressed as a percentage of PG’s total output. PES and PG shall
review and agree these weightings annually prior to submitting them to
the Commission for approval.

Changes in the fuel prices for a particular month will be forwarded by PG
to both PES and CER. An annual reconciliation process will be used by
PG and PES to determine and agree the overall financial under/over
1
recovery to be factored into the following years PG charges to PES for use
in tariff determinations.

Due to the interaction between the gas and electricity markets PG may,
on occasion, incur additional gas costs as a result of following dispatch
instructions. The Commission shall ex post review these costs to correct,
as appropriate.

Other reasonably incurred market driven costs including emergency
generation and rates are passed though to PES. Costs such as
transmission use of system charges will be passed through in full to PES.

Where the market driven costs and revenues are greater or less than the
forecast values the difference passed through to the BPA will be the net
value.

Controllable costs will be indexed to CPI and or the Programme for
Prosperity and Fairness - with in built efficiency factors.

The Agreement price may need to be adjusted for the volume of all PG
sales, e.g. if sales to PES, VIPP and top up, differ substantially from the
forecast levels.
2
2.
Overview
The BPA revenue that PG can derive from sales to PES is based on PG’s
estimated allowed costs, regulated market revenues (i.e. revenues not related
to the sale of electricity from PG to PES) and VIPP and Top Up sales
discounts. The estimated allowed costs are made up of Controllable Costs,
Market-driven Costs and Fuel Costs. The regulated market revenues consist
of payments for constraints, Top Up and Secondary Top Up, VIPP, system
support, ancillary services and capacity margin.
For year t ESB PG will estimate its annual costs, regulated market revenues
and VIPP/Top UP discounts and will submit these estimates to the
Commission for approval in May of year t-1, along with the annual sales
forecast from PG to PES as agreed by both parties. Following approval of the
amounts by CER, a BPA revenue for year t will be determined.
At the same time (i.e. May year t-1) ESB PG will submit a revised forecast for
year t-1 and a final outturn for year t-2 if applicable. In formulating the
transfer price for year t any net adjustment (K factor), arising from the
revised forecast of year t-1 and the final outturn of year t-2 verses the
amounts recovered/recoverable in these years, will be included. All K factors
will be recovered with interest as set out in Appendix 1. The timetable for
the process is detailed below.
Pre 2002
Pre 2002
May 2002
Sept 2002
May 2003
Sept 2003
May 2004
Estimated costs and market revenues for 2002
2002 Tariff determination
Estimated costs and market revenues for 2003
Revised forecast of costs and market revenues for 2002
2003 Tariff determination
Estimated costs and market revenues for 2004
Revised forecast for costs and market revenues for 2003
Actual outturn of costs and market revenues for 2002
2004 Tariff determination
Costs and market revenues for 2005 to be discussed
Revised forecast for costs and market revenues for 2004
Actual outturn of costs and market revenues for 2003
The total allowable cost that PG is allowed to recover in any year from PES
under this Bulk Power Agreement is calculated in euro million. This euro
million estimate is then translated in a €/MWh value that is profiled over
time to reflect the different values for electricity at the different times of year.
This provides PES with some efficiency incentive.
Figure 1 below provides the shape of the profiles for winter, summer and
spring/autumn weekdays and weekends that will apply in 2003.
3
Winter Wkday
Winter Wkend
Summer Wkday
Summer Wkend
Spr/Aut Wkday
23
21
19
17
15
13
11
9
7
5
3
1
Spr/Aut Wkend
Figure 1: Time of Day Profile
3.
Treatment of Peat Plants
For 2002 the BPA revenue will include revenue associated with PG’s peat
plants. From January 1st 2003 these plants will be operated under a PSO
levy mechanism (ref: S.I. 217 of 2002). The PSO levy will be a separate
charge included on electricity bills from all suppliers and will be collected
from all final users of electricity.
4.
Controllable Costs
Controllable costs are those costs over which PG can influence the outturn
value. The Commission has determined PG’s controllable costs as defined
in Table 2 below. In any year the allowed amount will only be adjusted for
actual inflation verses the inflation assumed in the May t-1 estimates.
The allowed values for controllable costs have been capped to incentivise PG
to operate efficiently and make cost savings. Any additional expenses
incurred will not be passed through to the final customer. Conversely, PG
may retain any savings against these values throughout the duration of the
price control.
4
Real 2001 Prices1
Payroll
Operations and maintenance
Non-recurring (minor)
Business services
Corporate centre
Depreciation
Employee and public liability
Environmental
Return on investment
Industry restructuring
PG Overheads
Closure
Total € million
2002
2003
2004
*
*
*
13,121
9,542
92,217
1,039
3,063
75,771
0
0
14,123
*
*
*
11,132
7,926
71,391
860
5,564
69,771
3,942
-4,876
0
*
*
*
11,904
7,362
71,391
860
9,957
64,774
3,942
-2,915
0
363,208
288,792
291,957
Table 2. Controllable costs
Notes:
1. * these values are not provided individually as PG considers this
information to be commercially sensitive.
2. All values are inflated by CPI with the exception of Payroll, Business
Services and Corporate Centre Costs.
Payroll is inflated by PPF
(Programme for Prosperity and Fairness).
Business Services and
Corporate Centre Costs are inflated by 50% PPF and 50% CPI. If a new
National Wage agreement is not reached payroll will be indexed at CPI
thereafter. The 2001 Real prices were based on an estimated inflation of
3.5% and will be adjusted to reflect the actual inflation rate.
3. The CER have approved an annual fixed sum for minor non-recurring
projects (< €2.5 M). The cost recovery for larger projects will be approved
on an individual case basis by CER.
4. PG’s share of Business Services and Corporate Centre costs allocated to
peat-fired plant have been included in 2002 and excluded thereafter.
1.
5
Prior to approving these values, CER reviewed estimates provided by PG
in its Revenue Submission Revised Forecast 2002 and 2003 Estimate.
1
5.
Market Driven Costs and Revenues
Market driven costs and revenues are those that are subject to market forces
and are, to varying degrees, outside PG’s control. In May of year t-1, PG will
submit estimates of all market driven costs and revenues for year t to the
Commission for approval. The 2002 forecast and 2003 estimates are detailed
in Table 3.
Except for non-recurring costs, any variance between the estimate, revised
forecast and actual out turn for the costs and revenues in Table 3 will be
recovered via the annual K factor. The treatment of non-recurring costs is
outlined in Appendix 5.
Market Driven Revenue2
2002
2003
Top up and secondary top up
7,866
23,600
180,118
108,960
1,229
1,229
Ancillary services
28,138
28,007
Constraint payments
17,391
17,391
VIPP
System support
Emergency generation
Capacity margin
Total € m – real 2001 prices
Market Driven Costs
Rates
Insurance
Emergency generation
System support
Powersave scheme
0
0
30,285
27,399
265,027
206,586
2002
2003
23,815
24,966
8,298
8,298
25,665
11,584
1,229
1,229
782
0
Purchased electricity (Spill)
27,039
16,025
Transmission use of system charges
32,829
28,746
*
*
Non-recurring
Constraint costs
17,391
20,070
Environmental
0
0
Total € m – real 2001 prices
*
*
Table 3. Market Driven Costs and Revenues
Revised per PG’s Allowed Revenue Submission Revised Forecast 2002 and
2003 Estimate
2
6
Notes to Table 3:
1. * these values are not provided individually as PG considers this information to
be commercially sensitive.
2. In the area of environmental expenditure, during the period of this Agreement
PG may face additional legal obligations. Subject to the Commission’s approval,
PG will be allowed to pass through all reasonable costs for compliance with all
future environmental requirements, including work that has to be carried out as
a result of station IPC licence requirements, compliance with emission bubble
limits, landfill levy and associated compliance/ mitigation costs, etc.
3. The Commission requires PG to demonstrate to the Commission’s satisfaction
that, whilst acting as a Reasonable and Prudent Operator, it maximises the level of
revenue or minimises the level of costs included in Table 3
4. The emergency generation costs for the period November 2000 to February 2001
will be recovered in the years 2003 and 2004

6.
5. PG will absorb the difference between the revenue received from VIPP and Top
Up as compared with the revenue that would have been received if these
products had been sold at the PES price (as determined in this Agreement). The
income differential amount, known as the “VIPP and Top Up discount”, will be
calculated using actually half hour data.
Allowed Fuel Costs
Fuel related expenditures are approximately fifty per cent (50%) of ESB PG’s
total costs. The Commission, in order to ensure that consumers do not bear
the burden of inefficient fuel purchasing, has linked the recoverable fuel
revenue to the market price for fuel. The Commission will allow PG to
recover the market price of fuel purchased in any given year. ESB PG will
carry the risk of any variance between actual costs and the market price for
fuel.3 The allowed fuel cost relates to PG’s sales volume less any spill
purchases.
In April of year t-1, an estimate will be made of PG’s fuel revenue based on
forecast market prices for year t and estimated total PG production.
This estimate will be used to generate a Reference Energy Price, Pt, and will
be an input to the calculation for the Tariffs in year t.
In the first year (2002, where t=0), Pt, will be set with reference to the
Commission’s proposed profit and loss account for PG as set out in the
Commission’s 12th September 2001 paper (with some adjustments reflecting
further consideration of points raised at that time).
For 2002 P0 is estimated to be € 30.12/MWh
ESB PG must document the causes of any significant variances that arise.
ESB PG will be permitted to retain explainable gains or losses due to hedging
contracts, purchasing agreements, etc. Any unexplainable windfall gains or
losses will be recovered / rebated in the following years.
3
7
Under the Grid Code, NG will supply PG with its Committed Outage
Programme for year t in October of year t-1. Using this schedule, PG and
PES will develop and agree revised fuel mix weightings annually based on an
unconstrained dispatch prior to submitting them to the Commission for
approval. When the Commission approves these weightings, they will then
be fixed for year t.
In April of year t-1, using a combination of actual volumes and fuel prices
(for January to March of year t-1), together with revised forecasts (for April to
December of year t-1), PG and PES will develop and agree a revised forecast
of total fuel revenue (i.e. for volume – total sales – spill) in year t-1 prior to
submitting them to the Commission for approval.
When approved by the
Commission, the revised fuel Cost (RFC) will be included in the calculation of
PG’s estimated allowable revenue for that year.
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 3

RFC    Pact .va   PRF .v RF 
M 4

 M 1
where:
M
is month in t-1
Pact
is the P value calculated using fuel weightings developed in
October of year t-2, and fuel prices as occurred in the relevant
months of year t-1.
PRF
is the P value calculated using fuel weightings developed in
October of year t-2, and forecast fuel prices for the relevant
months of year t-1.
vRF
is the forecast, made in April of year t-1, of monthly volumes of
PG sales less spill purchases, regarding months April to
December of year t-1 inclusive.
va
is the actual volumes of PG sales less spill purchases, as
occurred in months January to March of year t-1 inclusive.
Full details regarding the calculation of P values are given in Appendix 2.
8
Early in year t-1, actual values of all parameters for year t-2 will be known,
and the final actual fuel cost AFC can be determined as detailed below:
AFC 
12
[P
M 1
a ct
* va ]
where:
9
M
= month in t-2
Pact
= P value calculated using weights developed in October
of year t-3 and the actual fuel prices as occurred in each
month of year t - 2.
va
= actual volumes of PG sales less spill purchases as
occurred in the relevant months.
7.
Treatment of variation in total volume production
If PG either sells more or less volume that originally estimated and agreed
with PES, this will result in an over or under recovery of allowed revenue via
the BPA. Any such variance will be reflected in the annual K factor.
If PG’s total production (i.e. sales – spill purchases) either increases or
decreases when compared to the original estimate then this will result in a
change to the predicted fuel mix used to determine the allowed fuel cost
recovery.
PG has carried out a sensitivity analysis on its originally model. This
analysis indicates that for either an increase or decrease in output of 300
GWh, the change in plant output will be associated primarily with marginal
oil and gas plant in a 65/35 split respectively. The table below details the
associated composite efficiencies. These values will be used to adjust the
allowed fuel costs for any over/under production with respect to the original
estimate.
Plant type
Coal
Oil
Gas
8.
Weight
0
65
35
Efficiency
35.5
35.8
37.2
Other Issues
Changes to regulated wholesale prices
Changes to the regulated wholesale prices (i.e. top up and spill
arrangements) that affect PG’s income will be accounted for in the price
control and will leave PG financially neutral.
Treatment of gas penalties
There are a number of conflicts between the gas and electricity Codes that
may result in a generator incurring penalties under the gas code while
following the terms of the electricity code.
In view of this, an ex-post annual review will take place, for the purpose of
PG’s revenue control, to determine allowed revenue based on unavoidable
gas penalties. Where approved by the Commission, adjustments will be
made to the following year’s calculation of allowable revenue to include any
unavoidable penalties incurred.
Other Penalties
Under the Trading & Settlement Code and the Transmission Use of System
Agreement, penalties may be imposed upon PG by the Transmission System
Operator. PG may submit these additional costs to the Commission for
consideration in the following year’s review.
Where approved by the
10
Commission, adjustments will be made to the following year’s calculation of
allowable revenue to include any unavoidable penalties incurred.
Treatment of deferred income
In any year, some of PG’s revenue may be deferred. These values will be
recovered in the following year, where the deferred amount will form part of
the annual K factor.
11