APPENDIX B Actual to Approved Forecast Variance Explanations ACTUAL by kimbrozic

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									                                                                                APPENDIX B
                                                      2003 Actual to 2003 Approved Forecast
                                                                       Variance Explanations

2003 ACTUAL vs. 2003 APPROVED FORECAST

The following Appendix provides the detailed variance explanations between the 2003
Actual costs incurred by the AESO and the 2003 Approved Forecast.

The total 2003 Actual costs are higher than the 2003 Approved Forecast by $0.5M. This
variance consists 2003 Actual costs that are lower than the 2003 Approved Forecast for
Wires ($3.6M), Ancillary Services ($29.9M) and Other Industry Costs ($3.0M) offset by
2003 Actual costs that are higher than the 2003 Approved Forecast for Losses ($31.9M)
and General & Administration and System Controller Shared Costs ($5.1M).

These variances and the line number explanations that follow are provided in Table 5 of
the Application.


WIRES RELATED COSTS

Line 1 AltaLink

The 2003 Approved Forecast for AltaLink’s wires costs was $133.3 million. The basis of
this forecast was the Board Approved interim tariff. The variance between the 2003
Approved Forecast and the 2003 Actual costs of $136.2 million results from Board
Order, U2003-132, where the Board approved an increase in AltaLink’s Interim revenue
requirement, effective July 1, 2003.

Line 2 to 5 ATCO Electric Ltd.

ATCO was forecast to have net wires costs of $127.9 million in the 2003 Approved
forecast which includes $1.4 million for the Foster Creek Substation and a $6.1 million
offset for isolated generation. ATCO’s Actual costs for 2003 are $126.6 million, which is
relatively close to the forecast.

Line 6 ENMAX Power Corporation

ENMAX’s 2003 Approved Forecast was $34.4 million. On May 30, 2003 the Alberta
Department of Energy approved ENMAX’s 2003-2005 revenue requirement, in which the
amount for 2003 was $31.3 million. This represents the actual amount paid by AESO to
ENMAX during 2003.

Line 7 EPCOR Transmission Inc

EPCOR’s forecast wires costs were $34.0 million for 2003, as set out under its Interim
Tariff (U2002-1033). 2003 Actual net wires costs were $31.2 million. This difference is
due to an invoice which was received by the AESO in 2004 and was applied to 2004,
rather than to 2003. This invoice adjustment is an update to the 2003 Recorded amount
provided in the AESO’s 2004 Phase I Revenue Requirement Application.




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                                                                                   APPENDIX B
                                                         2003 Actual to 2003 Approved Forecast
                                                                          Variance Explanations

Line 8 City of Lethbridge

The City of Lethbridge actual wires costs for 2003 were $4.3 million, which is $1.5 million
greater than the 2003 Approved Forecast of $2.8 million for 2003. The Alberta
Department of Energy approved the 2003 revenue requirement of $4.3 million in a letter
dated May 30, 2003.

Line 9 TransAlta

TransAlta’s 2003 Approved Forecast wires cost was $2.7 million and there was no
significant variance from the 2003 Actual wires costs.

Line 10 City of Red Deer

The City of Red Deer’s 2003 Actual wires costs of $1.8 million did not vary from the 2003
Approved Forecast. Red Deer’s revenue requirement was also approved by the Alberta
Department of Energy in a letter dated May 30, 2003.

Line 11 Aquila Networks (Farm)

Aquila Networks Canada (Alberta) (“Aquila”) wires costs pertain to farm wires costs.
This $1.9 million Approved Forecast was obtained from Application No. 1250392, which
was approved by the Board in Decision 2003-053. The variance of $0.6 million between
Actual and Approved Forecast is due to Aquila receiving payment from the AESO as the
result of an under-collection for both the 2002 and 2003 calendar years.

Line 12 Unassigned Capital Additions

Forecast Unassigned Capital Additions now appear in the TFO’s actual amounts for
2003; as such there is no variance explanation.

Line 14 Invitation to Bid on Credits Agreements (IBOC)

Actual costs in 2003 are $0.3 million lower than 2003 Approved Forecast of $2.7 million.
The IBOC units ran less frequently in 2003 than forecast due to a reduction in actual
market heat rates from forecast.

Line 15 Location Based Credit Standing Offer Agreements (LBC SO)

Actual costs in 2003 are $0.3 million higher than 2003 Approved Forecast costs largely
due to the actual market heat rate in 2003 being lower than forecast.

Line 17 Prior Period Adjustment

This line item is a minor adjustment credit of $0.3 million from a prior period. The total of
the prior period adjustment is $0.7 million. The remainder of this adjustment is
distributed on a prorated basis to Losses, Ancillary Services and General and
Administrative Costs.




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                                                                                  APPENDIX B
                                                        2003 Actual to 2003 Approved Forecast
                                                                         Variance Explanations

ANCILLARY SERVICES

Lines 19 to 28 Operating Reserves

Actual costs for 2003 were $120.1 million or $46.9 million less than the $167.0 million
2003 Approved Forecast.

Costs have declined because prices for active and standby reserves declined in 2003.
The decline in prices is attributed to increased competition as new suppliers entered the
market. Partially offsetting the decline in per unit cost is the increase in active reserve
volumes that were required.

Active Reserves

       Active Reserve Costs & Volumes

                                                                 2003 Approved
                                                 2003 Actual        Forecast
          Costs ($M)                                $96.1            $122.2
          Volumes (MWh)                           5,291,495        5,176,135
          Average Hourly Volume (MWh)                604              590

2003 Actual Active Reserve costs are $26.1 million less than the 2003 Approved
Forecast.

Active Reserves are procured through the AS market or directly from suppliers through
Over-The-Counter transactions and are normally priced at a discount to pool price.
Actual costs in 2003 for Active Reserves were lower than the 2003 Approved Forecast
due to an increased number of suppliers having entered the market throughout 2003,
improving the discounts received for these services. In addition, the 2003 actual pool
price was lower compared to the 2003 Approved Forecast. Partially offsetting the lower
prices was slightly higher volumes due to load growth.

Additional Active Reserves were required as Alberta experienced an increase in load
growth and changes in interchange with neighbouring systems.

Furthermore, 2003 Actual costs for Active Supplemental Reserves were substantially
lower than the 2003 Approved Forecast due to the AESO under-forecasting the effect of
the hydro PPA on supplemental costs.

The details regarding the three components of Active Reserves, namely Regulating,
Spinning and Supplemental Reserves are provided below:




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                                                                               APPENDIX B
                                                     2003 Actual to 2003 Approved Forecast
                                                                      Variance Explanations

Line 19 Active Regulating Reserves

       Active Regulating Reserves Costs & Volumes
                                                              2003 Approved
                                             2003 Actual         Forecast
         Costs ($M)                             $42.2             $48.2
         Volumes (MWh)                        1,357,750         1,374,923
         Average Hourly                          155               157

Line 20 Active Spinning Reserves

       Active Spinning Reserves Costs & Volumes
                                                              2003 Approved
                                              2003 Actual        Forecast
         Costs ($M)                              $45.5            $49.3
         Volumes (MWh)                         1,967,601        1,900,651
         Average Hourly Volume (MWh)              225              217

Line 21 Active Supplemental Reserves

       Active Supplemental Reserves Costs & Volumes
                                                              2003 Approved
                                              2003 Actual        Forecast
         Costs ($M)                               $8.4            $24.7
         Volumes (MWh)                         1,966,144        1,900,651
         Average Hourly Volume (MWh)              225              217

Standby Reserves

2003 Actual Standby Reserve costs are $19.5 million less than the 2003 Approved
Forecast.

Standby reserves are procured through the ancillary services market or directly from
suppliers through Over-The-Counter (OTC) transactions. Standby reserve providers are
paid a premium for the option to call upon them to provide reserves. If the AESO
exercises this option, suppliers are also paid an activation price.

Due to an increased number of suppliers entering the market in 2003 actual activation
prices declined compared to the 2003 Approved Forecast. For this reason 2003 Actual
costs came in $19.5M under the 2003 Approved Forecast. Furthermore, a portion of
Active Regulating and Standby Reserves provided during 2003 were acquired from more
reliable plants that came on line during 2003. This led to reduced actual activations of
Regulating and Spinning Standby Reserves during 2003.

Line 23 Standby Regulating Reserves

As shown in the tables below, 2003 Actual costs for Standby Regulating Reserves are
lower than the 2003 Approved Forecast. This reflects the increased number of suppliers
that entered the market in 2003 causing premium and activation prices to decline.



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                                                                              APPENDIX B
                                                    2003 Actual to 2003 Approved Forecast
                                                                     Variance Explanations



Actual volumes for Standby Regulating Reserves in 2003 were lower than the 2003
Approved Forecast due to the AESO revising its daily forecast requirement midway
through 2003. This step was taken because the AESO had observed that the probability
of an activation occurring had steadily decreased.

Premiums

       Standby Regulating Reserve Premiums Cost & Volumes
                                                      2003 Approved
                                         2003 Actual     Forecast
         Costs ($M)                          $3.6          $6.7
         Volumes (MWh)                    1,164,656     1,506,880
         Average Hourly Volume (MWh)         133           172

Activation Costs

       Standby Regulating Reserve Activation Cost & Volumes
                                                        2003 Approved
                                          2003 Actual      Forecast
         Costs ($M)                          $6.2           $15.4
         Volumes (MWh)                      91,437         148,745
         Average Hourly Volume (MWh)          10              17

Line 24 Standby Spinning Reserve

The variance explanations for costs and volumes that apply to Standby Regulating
reserves also apply to Standby Spinning reserves.

Premiums

       Standby Spinning Reserve Premium Cost & Volumes
                                                     2003 Approved
                                        2003 Actual     Forecast
         Costs ($M)                         $2.9          $4.2
         Volumes (MWh)                    994,332      1,016,880
         Average Hourly Volume (MWh)        114           116

Activation Costs

       Standby Spinning Reserve Activation Cost & Volumes
                                                       2003 Approved
                                           2003 Actual    Forecast
         Costs ($M)                            $9.3        $14.9
         Volumes (MWh)                       124,229      156,395
         Average Hourly Volume (MWh)            14           18




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                                                                               APPENDIX B
                                                     2003 Actual to 2003 Approved Forecast
                                                                      Variance Explanations



Line 25 Standby Supplemental Reserves

2003 Actual Standby Supplemental activation costs and volumes were lower than the
2003 Approved Forecast. Volumes were lower because in 2003, Spinning Reserves
were occasionally being procured in place of supplemental reserves for economic
reasons. Premium costs were lower due to the lower volumes and the effect of more
participants improving liquidity.

Premiums

       Standby Supplemental Reserve Premiums Cost & Volumes
                                                     2003 Approved
                                        2003 Actual     Forecast
         Costs ($M)                         $0.9          $2.0
         Volumes (MWh)                    369,574       489,120
         Average Hourly Volume (MWh)         42            56

Activation Costs

       Standby Supplemental Reserve Activation Cost & Volumes
                                                       2003 Approved
                                         2003 Actual      Forecast
         Costs ($M)                          $2.4           $1.6
         Volumes (MWh)                      60,667         27,407
         Average Hourly Volume (MWh)          7               3

In addition, the AESO recovered an amount of $1.4M in 2003 (Line 27) associated with
trading fees and other charges which were costs not included in the 2003 Approved
Forecast as they were anticipated to net to zero.

Other Ancillary Services

Other Ancillary Services include Generator Remedial Action Schemes, Black Start,
Transmission Must Run, Under Frequency Mitigation, Hydro Motoring, Fort
Saskatchewan Load Shed, Poplar Hill and ILRAS.

Line 29, 33, 34 – Generator RAS, Hydro Motoring, Fort Saskatchewan Load Shed

2003 Actual costs are $2.3 million lower than the 2003 Approved Forecast due to:
   •   The AESO having renegotiated some of the Generator RAS agreements; and,
   •   The AESO having determined that Fort Saskatchewan Load Shed and Hydro
       Motoring is no longer required.

Line 30 Black Start

2003 Actual costs are $1.2 million lower than the 2003 Approved Forecast due to the
AESO not contracting with all the Black Start providers for the full year due to the
uncertainty surrounding liability protection issues in 2003.


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                                                                                 APPENDIX B
                                                       2003 Actual to 2003 Approved Forecast
                                                                        Variance Explanations



Line 31 Transmission Must-Run (TMR)

The 2003 Actual Cost of TMR is $45.2 million dollars, a substantial increase from the
2003 Approved Forecast of $26.1 million.

The majority of TMR costs are variable. These are structured in a manner that
compensates the TMR provider based on the ratio of the hourly pool price in $/MWh to
the cost of daily natural gas in $/GJ. This ratio is termed the market heat rate. If the
market heat rate is above heat rate TMR benchmarks specified in the contracts with
suppliers, no variable cost is incurred for TMR from that unit. Therefore the relationship
between variable TMR payments and market heat rate is:

   •   Lower the market heat rate, the higher the TMR costs; and,
   •   Higher the market heat rate, the lower the TMR costs.

The 2003 Actual cost increase in TMR cost versus the 2003 Approved Forecast arises
from the 2003 actual market heat rate (hourly pool price divided by daily natural gas
price) being lower than forecast. The AESO forecast the average market heat rate in
2003 to be 11.3, while the actual market heat rate for 2003 was 10.0.

Line 32 Under Frequency Mitigation

The 2003 Actual costs of $6.5 million were higher than the $5.2 million 2003 Approved
Forecast. Under Frequency Mitigation was engaged in 2003 more than had been
forecast in 2003.

Line 36 Poplar Hill Agreement

The 2003 Actual costs of $2.5 million were higher than the $1.9 million 2003 Approved
Forecast. In the 2003 Approved Forecast, the AESO under estimated the megawatts
required in 2003, leading to the increase in actual costs.

Line 37 Interruptible Load Remedial Action Schemes (ILRAS)

Actual ILRAS costs were $0.1 million in 2003, compared to an approved forecast of $0.5
million. The divergence between 2003 Approved Forecast and Actual costs is due to an
accounting adjustment that lowered 2003 Actual costs.




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                                                                                 APPENDIX B
                                                       2003 Actual to 2003 Approved Forecast
                                                                        Variance Explanations

LOSSES

Line 40 Pool Payment

       Transmission Losses Costs & Volumes

                                               2003 Actual       2003 Forecast
          Transmission Losses Cost               $174.6M            $142.7M
          Volumes (GWh)                        2,750 GWh          2,930 GWh
          Average Hourly Volume (MWh)           316 MWh            335 MWh

During the course of 2003 the system was operated in a more efficiently than was
forecast. The month of June, 2003 in particular was characterized with higher
generation output from generators located in Southern Alberta which contributed to the
actual losses being significantly below the 2003 forecast.

It should be also noted that the methodology used to produce the 2003 Approved
Forecast resulted in an over-stated losses forecast for the first six months of 2003. As
noted in the AESO’s Phase I Revenue Requirement Application, this methodology has
since been revised.

The reduction in actual losses in combination with an over-stated forecast for 2003
contributed to an over-collection of losses for the first six months of 2003.

The 2003 Actual cost is higher than the 2003 Approved Forecast due to a higher actual
pool price in 2003 than was forecast.

The 2003 Actual costs and volumes are updated from the 2003 Recorded amounts
provided in the AESO’s 2004 Phase I Revenue Requirement Application to include
additional losses billing adjustments since the time of filing that Application.




                                                                                 Page 8 of 14
                                                                                 APPENDIX B
                                                       2003 Actual to 2003 Approved Forecast
                                                                        Variance Explanations

OTHER INDUSTRY COSTS

Other Industry Costs are lower in the 2003 Actuals as compared to the 2003 Approved
forecast by $3.2 million.

Line 42 External Regulatory Costs

The 2003 Actuals of $7.7 million are lower than the forecast cost of $9.8 million by $2.1
million primarily due to the suspension of the Zonal Interconnection Charge (ZIC)
implementation hearing. The 2003 Actuals include recoverable costs arising from the
Congestion Management hearing, Article 24 (Rainbow & Rossdale) hearing, AESO
Liability Module as well as the AESO’s 2003 Negotiated Settlement.

Line 44 Share of AEUB Overhead

In 2003, the AESO recorded five-twelfths of the August 2003 to July 2004 allocation of
$1.988 million on a monthly basis. The actual allocation of AEUB overhead for the
period August 2002 to July 2003 of $1.7 million was booked entirely in the 2002 Actuals.
This results in a $0.8 favourable variance between these two periods.




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                                                                                APPENDIX B
                                                      2003 Actual to 2003 Approved Forecast
                                                                       Variance Explanations

GENERAL & ADMINISTRATIVE AND SYSTEM CONTROLLER SHARED COSTS

General & Administrative 2003 Actuals are higher than the 2003 Approved Forecast by
$5.1 million. The variances are driven by a net increase in salaries and consultants of
$6.0M and an increase in other General & Administrative expenses of $2.6M offset by a
decrease of $3.6M in System Controller Shared Costs. The System Controller became
part of the AESO in 2003 and these costs are now included in the General &
Administrative categories.

Line 46 Staff & Benefits Costs

The 2003 Actual is $4.4 million higher than the 2003 Approved Forecast of $8.3M, for an
annual cost of $12.7 million.

This increase is a result of significant changes that occurred to the staff complement
between the time the 2003 GTA application was filed in February 2003 and the
remainder of the year as the AESO integrated the predecessor organizations. The staff
increases in 2003 are due to the following factors:

       1) System Controller Shared Costs – Prior to the formation of the AESO, a
          System Controller Cost Sharing Agreement was in place between the Power
          Pool of Alberta and the Transmission Administrator of Alberta. This
          agreement allowed for the allocation of costs incurred by the Power Pool to
          the Transmission Administrator as they related to the System Controller
          function carried out at the Power Pool on behalf of the Transmission
          Administrator. Included in the 2003 Power Pool budget for the allocation was
          approximately $2.1 million in staff costs, representing approximately 21
          positions. These positions were filled by the former staff of the Power Pool
          and are now included in the transmission FTE count and staff expenses, as
          opposed to the lump sum amount under Other Industry Costs. The remaining
          $1.5 million of the total $3.6 million System Controller Costs can be attributed
          to capital costs ($0.6 million), consulting costs ($0.1 million) and other
          General & Administration ($0.8 million).

       2) Cost Allocation Impact on Existing G&A Costs – Subsequent to the
          formation of the AESO, a cost allocation study was conducted to establish a
          methodology for allocation of shared services costs and capital costs
          between the regulated and non-regulated functions of the AESO. This study
          was included in the 2004 Phase I Own Cost Application and approved by the
          Board in Decision 2004-012. In summary, approximately 75% of the
          operating costs of shared services for the entire AESO are allocated to the
          transmission function in 2003. The staff costs and FTE count are impacted
          by this allocation.

       3) Staff additions – With the formation of the AESO in mid-2003 and
          management’s assessment of the staff complement, 9.0 additional positions
          were added to the transmission function.




                                                                              Page 10 of 14
                                                                                 APPENDIX B
                                                       2003 Actual to 2003 Approved Forecast
                                                                        Variance Explanations

Line 48 Consultants

The 2003 Actual costs of $4.3 million for consulting is higher than the 2003 Approved
Forecast of $2.5 million by $1.8 million. The 2003 Actuals compared to the 2003
Approved Forecast are provided below. The details of the 2003 Approved Forecast
amounts have been obtained from the 2003 GTA ($2.2 million) and grossed up to
include the interconnection project consulting ($0.3 million).

In the course of a given year, some work is delayed or other projects are taken on in
their place, One offset to this increase in costs was due to the replacement of
consultants with FTE’s in the IT support area.

•   Among the more significant factors contributing to the $1.8 million overage were:

           $0.6 Million - Contractors and consultant resources were necessary to backfill
           vacancies in the early part of 2003.
           $0.2 Million - Unanticipated wind generation development activity in southern
           Alberta necessitated the AESO hiring additional planning and technical
           expertise in this area.
           $0.1 Million – Some consulting expertise was required by the TA to replace
           functions formerly performed by the Power Pool within the System Controller
           $0.1 Million – Consulting expertise was required to design Operating Policies
           as a result of the larger number of RAS schemes undertaken by the TA
           $0.1 Million – Recruiting expertise was required for the transition initiatives;
           recruiting costs were centralized in one location rather than assigning a
           portion to the ISO Transition Costs.
           $0.25 Million – This is a one-time item for non-recoverable hearing costs for
           the use of consultants in prior periods.
           $0.5 Million – Additional planning and planning policy support and
           development studies adapting to the changing provincial policy environment.

Line 47 and 49 Interconnection Fees (Offset)

In the 2003 Approved Forecast, $0.5 million was approved as the cost recoveries that
were anticipated to occur as a result of the AESO collecting application fees from
customers related to interconnection projects. The recoveries were allocated between
staff and consulting based on anticipated work requirements.

The 2003 Actuals include recoveries of $0.6 million which were close to the anticipated
amounts.

Line 52 Legal

Consists of costs for commercial, corporate and non-recoverable regulatory matters.
The 2003 actual amounts include non-recoverable hearing costs incurred in 2002 and
2003 that now results in the $0.6 million higher variance compared to the 2003 Approved
Forecast.




                                                                               Page 11 of 14
                                                                                 APPENDIX B
                                                       2003 Actual to 2003 Approved Forecast
                                                                        Variance Explanations



Line 54 Rent

The rent costs have risen by $0.3 million due to the integration and the subsequent cost
allocation study that supports that 70% of lease costs are now allocated to the
transmission function.

Line 56 Other Administrative Costs

                                                 2003 Approved
                                 2003 Actual        Forecast         Variance
Telecommunications                 $ 0.3M            $ 0.1M           $ 0.2M
IT maintenance and services          0.5               0.3              0.2
Office costs and dues                1.1               0.3              0.8
Total                              $ 1.9M            $ 0.7M           $ 1.2M

Actual Office costs and dues include corporate memberships, subscriptions, meals,
printing and recruitment. The variance from the 2003 Approved Forecast is a result of
unanticipated increases in costs related to the increased staff complement and
additional costs included in General & Administration that were previously a component
of the System Controller Cost Sharing. In addition, the allocation of a higher percentage
of total corporate office costs to the transmission function would increase the actual
costs, as supported in the cost allocation study approved by the Board in Decision
2004–012.

Line 59 Interest

2003 Actual interest costs are zero. The AESO incurred $0.4 million of interest in 2003
related to transmission functions due to excess Rider C refunds in Q4 2003 which
resulted in the AESO being in a short term borrowing position. This was offset for
deferral purposes by adjustments made for interest related to the TMR refunds for 2001
and 2003 resulting in a nil balance for interest.

Line 61 Tariff Deficiency and Correction Regulation Fee

The 2003 Tariff Deficiency Correction Regulation costs related to the acquisition of the
shares of ESBI Alberta Ltd. by the Power Pool Council, grossed up for taxes and
carrying costs of the debt and any transaction costs. This represents a one-time
expenditure. The 2003 Actuals do not vary from the 2003 Approved Forecast.

Line 62 ISO Transition Costs

These costs relate to the integration activities of the former Transmission Administrator
and the Power Pool of Alberta to form the AESO in accordance with the Act. The
integration costs are shared equally between the energy market and transmission
functions; the $1.2 million represents that transmission business portion for these non-
recurring costs. The 2003 Actuals do not vary from the 2003 Approved Forecast.




                                                                                Page 12 of 14
                                                                               APPENDIX B
                                                     2003 Actual to 2003 Approved Forecast
                                                                      Variance Explanations



Line 63 Taxes

The AESO is considered a non-for-profit organization which is not subject to corporate
tax. Prior to establishing the AESO in June 2003, the former Transmission Administrator
was considered a for-profit organization and the regulated activities were subject to
corporate tax. While the transmission administrator functions were managed by ESBI
Alberta Ltd. prior to October 2003, the corporate taxes were funded through the
management fee and not included in the annual revenue requirement. Subsequent to
the purchase of the ESBI Alberta Ltd. shares in October 2002 and before establishing
the AESO, the costs of corporate taxes were funded through the tariff. Therefore the
amount of $0.5M reflects taxes for January to May 2003.

Line 65 System Controller Shared Costs

The 2003 Approved Forecast included $3.6 million as a payment to the Power Pool for
System Controller costs. All 2003 costs from the Transmission Administrator and Power
Pool were allocated using the cost allocation methodology established for the AESO and
approved by the Board in Decision 2004-012. As a result of this change from the 2003
Approved Forecast, the System Controller shared costs appear throughout the General
& Administrative cost categories in 2003 Actuals.




                                                                             Page 13 of 14
                                                                                  APPENDIX B
                                                        2003 Actual to 2003 Approved Forecast
                                                                         Variance Explanations

CAPITAL

Line 69 Capital

Capital costs actually incurred in 2003 are $0.4M higher than the 2003 Approved
Forecast.

This variance is primarily driven by $0.8M in Furniture and Leasehold Improvement
costs incurred in 2003 to prepare for the move to a new office location in early 2004.
This amount is offset primarily by reduced costs related to the delay of IT initiatives.




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