# Presentation: 659616

## NETWORK AND ANCILLARY SERVICES

**PUBLIC INFORMATION FORUM**

## AGENDA

**Acronyms **
**Background**
**Network Service**
**Six Ancillary Services**
***Scheduling (Schedule 1)***
***Voltage Support (Schedule 2)***
***Regulation (Schedule 3)***
***Energy  Imbalance (Schedule 4)***
***Operating Reserves (Schedule 5 & 6)***
**Timeline of Activities**
**Contacts**

**Notes:**
This presentation will cover 
Some Acronyms used
A few slides on Background
Then we will talk about Network Integration Transmission Service
The bulk of the slides will talk about the Six Ancillary Services that are listed with their schedule #s
Finally we will give you a Timeline of Activities
 and list people to Contact

## ACRONYMS

**OATT - Open Access Transmission Tariff **
**LRS – Load Ratio Share**
**ATRR – Annual Transmission Revenue Requirement**
**CP – Coincidental Peak**
**BATO - Balancing Authority and Transmission Operations**
***Formerly Control Area***
**RR – Revenue Requirement for service**

**Notes:**
OATT - Open Access Transmission Tariff 
The next 3 relate to the network service
LRS – Load Ratio Share
ATRR – Annual Transmission Revenue Requirement
CP – Coincidental Peak

The industry is moving to replace the term Control Area with
Balancing Authority and Transmission Operations which we will list as the BATO

RR – Revenue Requirement for service will apply to the discussions of pricing the ancillary services

## BACKGROUND (1 of 2)

**Western’s OATT **
***January 6, 1998***
***to comply with FERC 888 ***
**Current – Rate Order No. WAPA- 84 **
***effective April 1, 1999 to March 31, 2004***
***Extended to March 31, 2006***
**Revised OATT filed January 25, 2005 **
***http://www.wapa.gov/transmission/oatt.htm***
**Proposed – Rate Order WAPA-127**

**Notes:**
As part of the back background I’ve listed some Western filings related to this rate order.

Western adopted an Open Access Transmission Tariff in spirit with FERC 888.  This is the filing which introduced Network and ancillary services describes each of the services in general terms
The current schedules for DSW were under Rate order WAPA- 84 Went in to Effect April 1, 1999 
And then Extended to March 31, 2006
I will be noting the differences between Current and the proposed rate
Western filed a Revised OATT on January 25, 2005 
It can be found on the Web site listed. 
The Proposed Rate Order is WAPA-127 

## BACKGROUND (2 of 2)

**Informal Meeting on June 27, 2005**
**Feed back Considered**
**DSW Established an External Web site**
_***http://www.wapa.gov/dsw/pwrmkt/ANCSRV/ANCSRV.htm***_

## NETWORK SERVICE (1 of 3)

**Network Service is Project Specific**
***PDP and Intertie are offered under this Rate Order***
***CAP is Offered Under a Separate Rate Order***
**Whole System Network Service **
***Only if Multi-System Transmission Rate is Approved***

**Notes:**
Network Integration Transmission Service is offered for each Project
Network Service for PDP and Intertie are offered under this Rate Order

Network Service for CAP is Offered Under a Separate Rate Order (WAPA-124) which is in public process now

A  DSW system wide Network Service or whole system service will be available if and only if a Multi-System Transmission Rate is Approved

## NETWORK SERVICE (2 of 3)

**Opens transmission systems to more customers**
***Customers charged for metered use ***
***Increases available transmission***
**Load Diversity**

**Notes:**
FERC proposed Network Service to open the transmission systems to more customers and generation suppliers
Each customer is charged for their metered use during the system peak hour each month

Transmission use varies from summer to winter, but a point to point service reserves the system as if the use was the same each month of the year

Additional transmission should be available because under the Network Service the transmission provider can take advantage of the load diversity.

## NETWORK SERVICE (3 of 3)

**Charge = LRS x 1/12 x ATRR **
**LRS = CP /system peak (by Project)**
**Monthly peak hour = hour Network customers’ loads is greatest**
**Rolling 12 month averages**
***12 CP***

**Notes:**
Network Service Customers will be charged according to a formula rather than by a certain rate
The monthly charge is the customer’s load ratio share (LRS) multiplied by one twelfth of the Annual Transmission revenue requirement

LRS is the customer’s monthly metered load coincident with the system peak divided by the system load at peak

The hour of the system peak is the hour during the month that the sum of the Network Service customers’ loads is greatest

Both the customer’s metered load and the system peak are averages of the previous 12 months which we call a rolling 12 month average  or 12 CP

## ANCILLARY SERVICES (1 of 2)

**Supplied from Generation Resources (except Scheduling)**
***Are necessary for transmission service***
***Correct effects of transmission transactions***
***Apply within BATO Area***
***Defined in Western’s OATT***

**Notes:**
Next I will talk about Ancillary Services 
All Ancillary Services (except Scheduling) are supplied from Generation Resources
They are necessary to provide basic transmission service, 
And needed correct the effects associated with undertaking a transmission transaction
These services apply to transactions within the Transmission Providers Balancing Authority and Transmission Operation (BATO) Area

## ANCILLARY SERVICES (2 of 2)

**Scheduling - Scheduling, System Control And Dispatch Service**
**Voltage Support - Reactive Supply And Voltage Control Service From Generation Resources**
**Regulation - Regulation And Frequency Response Service**
**Energy Imbalance Service**
**Operating Reserves**
***Spinning Reserve Service***
***Supplemental Reserve Service***

**Notes:**
Here is the list of the six FERC defined ancillary services which are offered in this rate order
Scheduling - Scheduling,  System Control, And Dispatch Service
Voltage Supply - Reactive Supply And Voltage Control Service From Generation Resources

Regulation - Regulation And Frequency Response Service

Energy Imbalance Service

2 Operational reserve services:

Spinning Reserve Service

Supplemental Reserve Service

## SCHEDULING SERVICE Schedule 1 (1 of 5)

**Schedule movement of Power**
***Through, out of, within or into BATO***
**Must be purchased from Transmission Provider**
**Proposed service Included in Transmission Rate**

**Notes:**
The first service we will talk about is the Scheduling Service
Which  recovers costs to needed to schedule movement of Power
Through, out of, within or into the Balancing Authority
This service must be purchased from Transmission Provider
If a customer has a transmission contract with DSW, the scheduling service will be included in the transmission Rate

## SCHEDULING SERVICE Schedule 1(2 of 5)

**Annual costs are Labor and Capital costs **
**Based on E-Tag**
***Primary method for communicating Interchange Scheduling Information***
***Relevant information to identify a  transaction***

**Notes:**
This slide speaks to what goes into the Scheduling Service charge 
The costs which are recovered through this service are the annual cost of all personnel and capital costs associated with the service 
Personnel would include pre & post schedulers and dispatchers 
An example of capitol costs is the control center building
The unit on which this charge is based is the E-Tag

E-Tags are used because all transmission providers are required to use them as the primary method for communicating Interchange Scheduling Information

And the E-tag contain the relevant information to identify a  transaction

## SCHEDULING SERVICE Schedule 1 (3 of 5)

**Steps to determine rate**
***1) Annual capital costs divided by the number of tags from previous year***
***2) Determine average labor cost per tag***
***3) Add to capital cost per tag ***
**Rate = capital cost for service/# of Tags/yr + labor cost/Tag**

**Notes:**

The rate is designed around in 3 major steps  
1) All the yearly costs for capital improvements are added together and divided by the number of tags issued during the previous year.  
2) Next the average labor cost per tag is determined by estimating the average time spent creating a tag 
3) The labor cost per tag is added to the capital cost per tag 

The basic formula for the rate is
= capital cost for service/# of Tags/yr + labor cost/Tag

## SCHEDULING SERVICE Schedule 1 (4 of 5)

**Capital Cost per Tag = $14.35**
**Labor Cost per Tag = $4.26**
**Cost per Tag = $18.61**
***	******	******	******	******	******	***_**[$](file:///Sched%20Charg.xls)**_

**Notes:**
The proposed rates for the scheduling service 
using recent data are shown

Capital Cost per Tag = $14.35
Labor Cost per Tag = $4.26
Cost per Tag = $18.61

## SCHEDULING SERVICE Schedule 1 (5 of 5)

**For Current**
***Rates based on schedules ***
***Four Rates ***
**Combinations of new,  existing, with intra bus transfers, with no intra bus transfers**
**Proposed Rate**
***Based on Tags***
***One rate***

**Notes:**
This slide shows the main differences between Current rate methodology and the proposed methodology
Under Current methodology

Rates were based on schedules because 
E-Tagging was not used

The rate distinguished between new and existing schedules and between those which included intra bus transfers and those which did not

Under the proposed rate the charges are on a per tag basis

And one rate is calculated since the E-tag replaces the need to break out the schedule into different components

## VOLTAGE SUPPORT Schedule 2 (1 of 5)

**Maintain Voltage levels on System**
**Injections or Absorption of  VARs**
**Must be purchased from Transmission Provider**

**Notes:**
The Voltage Support service is used to 
Maintain Voltage levels on the Transmission System mainly by injecting or absorbing the portion of apparent power called  VARs  
This service must be purchased from Transmission Provider because the provider must support the voltage output

This service does not relieve the customer from maintaining  a specified power factor at the interconnection to the system

## VOLTAGE SUPPORT Schedule 2 (2 of 5)

**Equipment**
***Static VAR Support ***
***Generating units ***
**Static Costs recovered in transmission rate**
**Generation-related costs covered in this proposed rate**

**Notes:**
There are 2 general types of equipment that can supply VARs for this service

One type is Static VAR equipment which is installed transmission grid.  Some examples of this are 
Capacitors and 
Static Var compensators
These Costs are included in the basic transmission charge

The other type of equipment which can supply VARs is 
Generating units.
The VAR output depends on how a unit is loaded at a given time.  
These costs covered in this rate

## VOLTAGE SUPPORT Schedule 2 (3 of 5)

**Rate = RR ****÷ (****Capacity Using Service)**
**RR = Gen RR * % used for Voltage Support**
**RR for service  = **
***BCP Base Charge x (1 – PF******BCP******) + ***
***PDP Gen RR x (1 – PF******PDP******) + ***
***CRSP Gen RR x (1 – PF******CRSP******)***
**Capacity = DSW Transmission capacity minus capacity of IPPs**

**Notes:**
The basic formula to determine the Voltage Support rate 
= (RR for Service) ÷ (Capacity Using Service)

DSW uses power factor of the facility to determine the % of RR of each Project that will be used for the service
That is 
RR for service  = BCP Base Charge x (1 – PFBCP) + 
		PDP Gen RR x (1 – PFPDP) + CRSP Gen RR x (1 – PFCRSP)

To determine the Capacity using service we take the 
 DSW Trans capacity and subtract the capacity of IPPs

## VOLTAGE SUPPORT Schedule 2(4 of 5)

| RATE 
kW-Yr | $0.52 
 |
| --- | --- |
| RATE 
kW-Mo
 | $0.043 
 |

**Notes:**
This table shows the rate expressed on a kilowatt year  and a kilowatt month basis

## VOLTAGE SUPPORT Schedule 2 (5 of 5)

**Current**
***Capacity * (1-PF******2******)***
***CRSP MC calculates capacity***
***all reservations in Control Area***
***Expressed monthly rate to 2 decimal places***
**Proposed Methodology**
***Capacity * (1-PF) – all Projects***
***Used PDP operational flows***
***Capacity Excludes IPPs***

**Notes:**
Here we show the differences between Current and Proposed methodologies
Under Current method

DSW Applied formula to PDP and BCP and used the factor of (1 – power factor squared)  but took a calculated RR that the CRSP Management Center supplied

For the denominator, we considered all transmission reservations in the Balancing Authority and we

Expressed monthly rate to 2 decimal places

We are Proposing to a method which 

Applies factor (1 – PF) to all 3 projects 

Applies PF based on PDP operational flows and
Excludes IPPs capacity because their contracts require they supply the service to WALC when requested.

## REGULATION  Schedule 3 (1 of 8)

**Continuous balancing of resources with load **
**Maintain frequency**

**Notes:**
The next slide speaks to Regulation
Regulation is necessary to 
Provide for the continuous balancing of resources with load in the Balancing Authority
Resources may come from generation and/or  interchange energy

This service is also needed for maintaining scheduled interconnection frequency at sixty cycles per second (60 Hz)

## REGULATION  Schedule 3 (2 of 8)

**AGC and SCADA equipment and generation **
**Generation used for regulation**
***Cannot be used for other services***
**Frequent changes in output**
***Increased O&M costs***
***Increases wear and tear***

**Notes:**
The regulation service utilizes a portion of generation resources that are spinning as well as Automatic Generation Control and Supervisory Control and Data Acquisition equipment

Although we don’t set a side specific generation capacity dedicated for regulation, at any given moment, capacity used for regulation cannot be used to provide other services

Regulation requires frequent changes in output as it follows changes in the load
This results in increased O&M costs and 
Increases wear and tear on the generation equipment

## REGULATION  Schedule 3 (3 of 8)

**No long-term sales **
*Except as bundled in the FES*
**Market Price plus procurement cost if requested**
**Short-term sales from DSW resources if available**
*Proposed rate (next slide)*

**Notes:**
In DSW, regulation capacity is not available on a long-term basis other than that which is bundled in the FES 
If a customer needs this service and Western can’t supply it from DSW resources, we will purchase regulation on the open market will pass on the cost of procuring the service

Western will provide regulation from DSW resources only on a short-term basis and only if such resources are available

When available, short-term regulation services from DSW resources will be provided at the proposed rate as shown on the next slide

## REGULATION  Schedule 3 (4 of 8)

**Rate = RR /BATO load requiring the service**
**RR for service = **
***(Capacity for service x Capacity rate of Project + Regulation Purchases) x use factor***
**BATO load requiring the service = **
***CRSP Southern load + DSW load + Additional Load in BATO***

**Notes:**
The general formula for determining the regulation rate 
= RR for Regulation divided by the reservations requiring the service

The revenue requirement  for service is 
=(Capacity for service x Capacity rate of Project + Regulation Purchases) x use factor

Reservations requiring the service = 

CRSP Southern load + DSW load + Additional Load in BATO

## REGULATION  Schedule 3 (5 of 8)

| Regulation Capacity 
RR | $918,932 
 |
| --- | --- |
| BATO Load 
Requiring
Service | 4,483,892 MWhr
 |
| Regulation
Rate | 0.2049 mills/kWhr
 |

| .  |
| --- |

**Notes:**
This slide shows a table with the final values for the rate calculated with recent data.

## REGULATION  Schedule 3 (6 of 8)

**Limited capacity estimated for regulation: **
**Abnormally high load variations **
*use additional services*
*Example: smelters and arc furnaces*
*require additional metering*

**Notes:**
next i want to introduce the concept of regulation service for non-standard loads

Western estimates that it will need to use a certain amount of regulation based on normal system loading

Customers with abnormally high load variations use more regulation services than customers with average load variations

Some examples would be loads associated with 
smelters and arc furnaces

Such non-standard loads require separate metering to accurately calculate their effects on the system

## REGULATION  Schedule 3 (7 of 8)

**A single plant or site **
**Incremental regulation capacity requirement**
*** ******5 MW or greater on a reoccurring basis; and***
***Capacity requirement equal to 10% or greater of their average load***
***determined by Western****** ***
**Provided for in a separate service agreement **
**Compensates for the additional burden **

**Notes:**
A non-standard load shall be defined as either a single plant or site with: an incremental regulation capacity requirement of:

 5 MW or greater on a reoccurring basis; and

Capacity requirement equal to 10% or greater of their average load

Non-standard load entities, as determined by Western, shall be charged the pass-through costs of such incremental regulation to Western, plus any costs associated with procurement and monitoring the service 

## REGULATION  Schedule 3 (8 of 8)

**Current**
***Capacity rate of project supplying service***
***Non-standard load not considered***
**Proposed Methodology**
***Formula determined RR***

**Notes:**
differences between current and proposed regulation methodology are as follows
Under the Current methodology
We use the Capacity rate of project supplying service
And we Did not consider non-standard loads 

We Propose to use a Revenue Requirement determined by portion of generation used for Regulation

The denominator is the Capacity which requires the service

## ENERGY IMBALANCE Schedule 4 (1 of 6)

**Difference between scheduled and actual delivery of energy on hourly basis**
**Make up imbalance energy deviations **
***scheduled energy or***
***Pay the cost of the imbalance energy****** ***
**Energy deviation bandwidth**
***Helps load only customers ***
***Different consequences ***

**Notes:**
Energy Imbalance is defined as the difference between scheduled and actual delivery of energy located within the Balancing Authority.
The customer must either make up imbalance energy deviations with scheduled energy within a certain time period; or
Pay the cost of the imbalance energy that is provided by the transmission provider
FERC introduced the concept of the energy deviation bandwidth in part because
Customers with no generation find it harder to meet their schedules exactly 
Also this rate recognizes different consequences to transactions within and outside the bandwidth

## ENERGY IMBALANCE Schedule 4 (2 of 6)

**Energy Bandwidth**
***On-Peak = +/- 1.5% with a min. of 5 MW (Over Delivery or Under Delivery)***
***Off-Peak = +1.5% to -3% with a min. of 2 MW (Over Delivery) and 5 MW (Under Delivery)***

**Notes:**
The proposed energy bandwidth is different for transactions that occur during on-peak hours than for those occurring during off-peak hours
Specifically
On-Peak = +/- 1.5% with a min. of 5 MW (Over Delivery or Under Delivery)

Off-Peak = +1.5% to -3% with a min. of 2 MW (Over Delivery) and 5 MW (Under Delivery)

## ENERGY IMBALANCE Schedule 4 (3 of 6)

**Energy Within the Bandwidth**
***On-Peak = 100% of Weighted Index price ***
***Off-Peak = 100% of Weighted Index price***
***Western’s determines whether settlement is scheduled return of energy or a monetary settlement***

**Notes:**
For Energy deviations Within the Bandwidth 
for both On-Peak and Off-Peak 

The settlement is 100% of the Weighted Index price

Western will determine what index will be used and

For all cases it is at Western’s discretion to require a scheduled return of energy or a monetary settlement

## ENERGY IMBALANCE Schedule 4 (4 of 6)

**Energy Outside the Bandwidth**
***On-Peak***
**110% of Weighted Index price for Under Deliveries and  **
**90% of Weighted Index price for Over Deliveries **
***Off-Peak***
**Under Deliveries Settlement 110% of Weighted Index price**
**Over Deliveries Settlement Greater of 60% of Weighted Index price or WALC weighted sales price**

**Notes:**
This slide talks about Energy Outside the Bandwidth
For transaction in On-Peak hours

The settlement is 110% of Weighted Index price for Under Deliveries and  
90% of Weighted Index price for Over Deliveries 

During Off-Peak hours
The settlement for Under Deliveries is 110% of Weighted Index price 
For Over Deliveries the settlement is the Greater of 60% of Weighted Index price or WALC weighted sales price
As determined by Western

## ENERGY IMBALANCE Schedule 4 (5 of 6)

**Rate Order WAPA-84 **
**FERC pro-forma was used**
***+ or - 1.5% bandwidth w/ 2 MW deviation minimum ***
***Under-deliveries assessed 100 mills/kWh penalty***
***Over-deliveries credited 50% of market value***

**Notes:**
The next 2 slide compare current to proposed
Under the current methodology 
DSW used the FERC pro-forma methodology
That is 
A band width of plus or minus 1.5 % of load
with 2 MW minimum deviation.
Under-deliveries were assessed a penalty of 100 mills/kWh
And Over-deliveries credited 50 % of market value if available

DSW reserved right to wave penalties

## ENERGY IMBALANCE Schedule 4 (6 of 6)

**Proposed Rate **
***Uses market value of energy for Settlement***
***Treats on-peak differently than off-peak***

**Notes:**
Under the Proposed Rate Methodology 
The  market value of energy is used to determine the amount of a  Settlement.   

The market value is based on an index of Western’s choosing

Also deviations which occur during on-peak hours are treated differently than deviations which occur during off-peak hours

## OPERATING RESERVES  Schedule 5 & 6 (1 of 3)

**Hedge on generation or transmission outages (contingencies)**
**Two Schedules:**
_***Schedule 5: Spinning Reserves***_
**Synchronized to the system **
**serve load at time of event; or **
**Load removable at the time of the contingency **
_***Schedule 6: Supplemental Reserves***_
**Synchronize to the system within 10 minutes**
**serve load within 30 minutes **
**Load removable within 10 minutes**

**Notes:**
Operating Reserves –help customers recovery from unexpected generation or transmission outages
DSW is proposing two types Spinning and Supplemental:
Spinning Reserves refer to either
Generation synchronized to the system and fully available to serve load at the time of the contingency event; or 
Load removable from the power system at the time of the contingency event. 
Supplemental Reserves refer to either
Generation capacity capable of serving load within a short period of time 		
That is Units that can be synchronized within 10 minutes and fully available within 30 minutes
Or Load removable within 10 minutes

## OPERATING RESERVES  Schedule 5 & 6 (2 of 3)

**Not available on a long-term basis**
***Open market plus cost to procure***
**Short-term from DSW Resources if available**
***Priced at Market based rates***

**Notes:**
Operating Reserves are not available from DSW resources on a long-term basis

However, DSW will purchase reserves on the open market and will pass on these costs plus any costs needed to procure the service 

DSW will provide Operating Reserves from DSW resources only on a short-term basis and only if such resources are available
In this instance short-term reserve services from DSW resources will be provided at Market based rates

## OPERATING RESERVES  Schedule 5 & 6 (3 of 3)

**Current **
***Market based rate plus 10%***
**Proposed Rate**
***Market based rate plus cost to procure***

**Notes:**
There is not much differences between the current rate and the proposed rate because DSW has never had reserves to sell on a long term basis.  

In the Current methodology we used a 10% administrative fee plus the pass through cost of the service

In the Proposed rate, DSW will simply charge the pass through cost and the cost to procure the service.

## TIMELINE OF ACTIVITIES

| Action | Date |
| --- | --- |
| Federal Register Notice was Published | 10/12/05  |
| Beginning of the Comment Period | 10/12/05  |
| Public Information Forum (PIF) | 11/02/05  |
| Public Comment Forum | 11/29/05 |
| PIF Response Letter Send to Customers | 12/20/05  |
| Close of Comment Period | 1/10/06  |
| Effective Date of the Rate | 4/1/06  |

**Notes:**
Next I will show the intended time line for this process
Federal Register Notice was Published	Oct 12-05	
Which Began of the Comment Period	Oct 12 -05	
Public Information Forum (PIF) today	Nov 2-05	
Public Comment Forum		Nov 29-05	
Letter to Customers responding 
to any questions not answered 
From this forum 			Dec 20-05	
Close of comment Period		Jan 10-06	
Effective Date of the Rate		April 1-06	

## CONTACTS

**Jack Murray **
***(602) 605-2442  ***
_***[jmurray@wapa.gov](mailto:jmurray@wapa.gov)***_
**Brian Young**
***(602) 605-2594***
_***[byoung@wapa.gov](mailto:byoung@wapa.gov)***_
**Bill Snowden**
***(602) 605-2766***
_***[snowden@wapa.gov](mailto:snowden@wapa.gov)***_

## CONTACTS

**Jack Murray **
***(602) 605-2442  ***
_***[jmurray@wapa.gov](mailto:jmurray@wapa.gov)***_
**Brian Young**
***(602) 605-2594***
_***[byoung@wapa.gov](mailto:byoung@wapa.gov)***_
**Bill Snowden**
***(602) 605-2766***
_***[snowden@wapa.gov](mailto:snowden@wapa.gov)***_