CALIFORNIA	
INDEPENDENT SYSTEM OPERATOR
CORPORATION
151 Blue Ravine 
Folsom, California  95630 

October 17, 1997

Ms. Lois D. Cashell									
Secretary
Federal Energy Regulatory Commission
888 First Street, N.E.
Washington, D.C.  20426

Re: Section 35 Rate Filing of the California ISO, California Independent System Operator Corporation, Docket No. ER98-___-000

Dear Ms. Cashell:

Pursuant to Section 35.13(a)(1) of the Commission’s Regulations, 18 C.F.R. § 35.13(a)(1), the California Independent System Operator Corporation (ISO), hereby submits its rate filing for approval in the above-referenced proceeding.  The ISO seeks approval of the Grid Management Charge, a formula rate designed to collect the costs of operating the ISO.  In addition, the ISO is filing rate schedules for approval of certain “pass-through” charges for Ancillary Services, Congestion Management and Wheeling Access, all of which the ISO will pass through to Scheduling Coordinators based on the ISO’s cost of providing the service or the market clearing price.  The ISO requests that these rates be allowed to go into effect on January 1, 1998.  

INTRODUCTION
	
The California Legislature, in Assembly Bill 1890, State of California 1995-96, Regular Session, September 24, 1996 (AB 1890) and the California Public Utilities Commission in a series of opinions in R.94-04-031 and I.94-04-032, required the ISO to create a new independent legal entity to take over the operation and control of transmission facilities in the State of California.  In compliance with these orders, the ISO has established a new and complete transmission control center containing the necessary computer and communication equipment.  It has also and hired experienced staff to safely and operate reliably the transmission facilities under its control.  AB 1890 required the ISO to begin operations by January 1, 1998, the same time that retail access begins in California.  On August 15, 1997, the ISO submitted its Amended and Restated ISO Tariff, which is now pending before the Commission in Pacific Gas & Electric Company, et al, Docket Nos. EC96-19-003 and ER96-1663-003.  The present filing contains the rate schedules that will become Appendix L of the August 15, 1997 tariff.  Preparation of the protocols and procedures is expected to be completed and filed at the Commission, for informational purposes, by November 1, 1997.

The ISO is currently on schedule to begin operating on January 1, 1998.  During the third quarter of 1997, the ISO completed the systems development work, and the system is now being tested.  The three IOU utilities – Pacific Gas & Electric Company (PG&E), Southern California Edison Company (SCE), and San Diego Gas & Electric Company (SDG&E), will transfer their Area Control Center (ACC) operations to the ISO before January 1, 1998.  As of the time of this filing, the ISO has hired 170 of its projected staff of 273 full-time equivalents.   

The ISO is aware of the burden that it has placed on the Commission’s resources in requesting authorization to begin operating on January 1, 1998.  The ISO has made every effort to complete this filing as soon as possible.  The ISO staff, however, only received approval of its 1998 Operating Budget from the ISO Board of Governors on September 10, 1997.   Since that time, the ISO has developed a financing plan and prepared the Section 35.13 cost statements and testimony.  In addition, the ISO initiated a stakeholder meeting at which the ISO presented a draft of its proposed rate structure.  That meeting has given the ISO the opportunity to address many of the stakeholders’ concerns in this filing.  

COMMUNICATIONS

Correspondence and other communications regarding this filing should be directed to: 
		Jeffrey D. Tranen    
	    	Charles A. Smart
California Independent System Operator Corporation
		151 Blue Ravine 
Folsom, CA  95630
(916) 351-4450
            fax (910) 351-2189

Ray S. Bolze
                         	Stephen Angle
Linda L. Walsh
Howrey & Simon
1299 Pennsylvania Avenue, N.W.
Washington, D.C.  20004
(202) 383-7261
fax (202) 383-6610  

SUMMARY OF FILING

	In this filing, the ISO seeks approval of its Grid Management Charge and other rate schedules for various transmission services provided by the ISO.  This filing consists of the testimony of the ISO’s Chief Financial Officer, Mr. Charles A. Smart, who testifies regarding the ISO’s cost of service, the Section 35.13 Cost Statements and the Rate Schedules, which will constitute Appendix L of the ISO’s August 15, 1997 Tariff.  Ms. Sandra S. McDonald of J.P. Morgan Securities describes the financial structure and debt service requirements of the ISO included in the Grid Management Charge.  Mr. Seabron C. Adamson of London Economics, Inc., explains the estimate of the transmission volumes that the ISO expects to flow on the ISO Controlled Grid during 1998.  The testimony and accompanying cost support show that the proposed GMC of $0.7342/MWh is just and reasonable.     

	The ISO also seeks approval for certain pass-through charges for Ancillary Services, Congestion Management, and Wheeling Access.  Charges for Spinning Reserves, Non-Spinning Reserves, and Replacement Reserves will be determined through the ISO Ancillary Service auction process.  Charges for Voltage Support and Black Start Capability will be equal to the ISO’s cost of procuring these services from providers.  Finally, the ISO’s charges for Intra- and Inter-zonal Congestion Management will be equal to the market clearing price at the time and location of the congestion.

CONTENTS OF FILING

	The following documents are included with this filing:
Transmittal Letter
Notice of Filing
		Attestation of Corporate Accounting Officer
Certificate of Service
Testimony of Charles A. Smart, Chief Financial Officer (CAS-1)
Operating Budget Summary Sheets (CAS-2)
Budget Process Summary CAS-3)
Rate Schedules – ISO Tariff Appendix L (CAS-4)
Cost of Service Statements AA through BM (CAS-5)
Workpapers for Operating Budget and Cost Statements  (CAS-6)
Testimony of Sandra C. McDonald, Vice President, J.P. Morgan 
Securities (SSM-1)
Testimony of Seabron C. Adamson, President, London 
Economics, Inc., (SCA-1 through SCA-11)

BUDGET PROCESS

The ISO’s Operating Budget has two basic elements: 1) the Start-up and Development Costs incurred prior to January 1, 1998 to establish the ISO’s basic infrastructure and operating systems; and 2) the ongoing Operating Budget for the ISO beginning on January 1, 1998. 

The ISO’s projected budget was developed using a “top-down” and “bottom-up” approach as described in Exhibit CAS-3.  The ISO’s interim staff and accountants developed a top-down budget for the organization based on the initial cost estimates provided by the IOUs, refining them as the ISO developed.  The ISO staff, under the direction of the Chief Financial Officer, Mr. Smart, developed independent bottom-up budgets for each department.  In integrating the two approaches, the ISO staff and accountants were careful to ensure that all projected costs were accounted for in the budget and that no costs were double counted.  A copy of the ISO’s projected Operating Budget for 1998 and 1999 is attached as Exhibit CAS-2, and includes the ISO’s projected capital expenditures through 1999.  The ISO Board of Governors approved the 1998 Operating Budget projections.  The 1999 Operating Budget is still preliminary and will not be submitted to the Board of Governors for approval until the end of 1998.  It is included in Exhibit CAS-2 for illustrative purposes only.   

The ISO’s governance structure provides a built-in mechanism to keep downward pressure on the ISO’s operating costs.  The Board of Governors is made up of members that are broadly representative of California electricity users and providers (i.e., investor-owned utility transmission owners, publicly-owned utility transmission owners, non-utility electricity sellers, public buyers and sellers, private buyers and sellers, industrial end-users, commercial end-users, residential end-users, agricultural end-users, public interest groups, and non-market participant representatives.  This diverse group sets the ISO’s goals and objectives and approves all major actions, including the ISO’s Operating Budget.  The ISO cannot exceed its approved budget without the Board of Governors’ authorization.  It is in the best interest of all members of the

Board of Governors, who are representative of all users of the ISO, that the ISO maintain a reliable transmission system at the least cost.  

1.	Start Up and Development Costs

As required by AB 1890, the ISO is responsible for creating an entirely new entity to take over the operation and control of transmission facilities in the State of California.  To meet this obligation, the ISO has established a complete transmission control center with the necessary equipment and staff to safely and reliably operate the transmission facilities under its control.  

The Start-Up and Development costs amount to approximately $178,466,000 and consist of costs related to all of the ISO activities up through December 31, 1997, including equipment purchases, trust administration expenses, consultant and legal fees, salaries, facility construction, the hardware and software for the Power Management System, the Scheduling Infrastructure, the Scheduling Application System and Balance of Business Systems, the meter and data acquisition and communications infrastructure, the leasehold improvements for the primary and satellite centers to accommodate the computer and communication infrastructure necessary for the ISO’s operations, and the specific project development costs to be incurred in 1998 and 1999.  CAS-1 at 11.  Many of the initial Start-Up and Development cost estimates were initially developed by PG&E, SCE and SDG&E, based on their own equipment and staffing needs to control transmission facilities.  Some of the Start-Up and Development costs, amounting to $23,303,000, will be incurred after the commencement of operations in 1998.

As discussed below, the Start-Up and Development costs will be financed when the ISO issues bonds in early 1998.  The cost of servicing the principal and interest on the bonds, rather than asset depreciation, will be collected through the Grid Management Charge.   

2.	Operating Budget 

The ISO’s forecasted Operating Budget is shown in the table below:

California Independent System Operator Corporation
Estimated Operating Budget
(in 000’s)
								    1998	     1999

Salary and Benefits			     		$36,376	 $35,851
Building, Leases & Facility Costs 	        	   	    2,261	     2,464
Insurance						       620	        625
Third Party Vendor Contracts		            	  47,799	   46,603
	Professional and Consulting Services		   	    5,615	     5,525
	Legal, Regulatory and Consulting			    5,500	     5,200
	Training, Travel and Professional Dues 	                3,348	     3,315
	Other						                2,124	     1,773
	Contingency						    5,486	     5,420
		
Total Operating Expenses          	           $109,129         $106,775

The ISO expects its 1999 operating expense budget to decrease because a portion of the 1998 Operating Budget includes a certain amount of costs relating to getting the ISO up and running.  The 1999 Operating Budget is preliminary and subject to change.

Salaries and Benefits

The salaries and benefits plan for the ISO’s employees was based on the 50th percentile of market data obtained from various industries, including the utility industry, power trading, financial services, and west coast industrials.  The goal was to balance the need for flexibility and cost efficiency with the need to be competitive in attracting knowledgeable and experienced individuals to get the ISO started and operating in a safe and reliable manner.  CAS-1 at 13.

Building and Facilities

The ISO has established primary and satellite operation centers at two geographically separate locations to house the ISO’s equipment and personnel.  The primary facility is in Folsom (in the Sacramento area) and the satellite facility is in Alhambra (Los Angeles area).  The $2.261 million in operating costs covers the primary and satellite leases and the primary and satellite operating and maintenance costs.  (CAS-2 at 5).

Third Party Vendor Contracts

The ISO’s third party vendor contracts, which total $47.799 million, include four major service contracts.  CAS-2.  First, the MCI Communications and Services Contract will support the ISO’s communications infrastructure.  The ISO’s communications infrastructure consists of a private, state-wide network for voice and data communications that will allow the ISO to communicate with Scheduling Coordinators to control and monitor the power grid and to provide the facilities for transporting metering data. The fixed amount of the MCI service contract will be $28,433 million in 1998.

Second, the IBM Computing and Services Contract will provide computing equipment along with service and maintenance for the three-year life of the contract.  The contract provides for four main services: 1) a Cost Center/Help Desk will be the first level of contact to assist internal ISO staff and external users of the ISO’s communication facilities; 2) Office Automation Services will supply ISO staff with computers and other office equipment and provide support systems such as e-mail, directory systems, copiers, and fax machines; 3) a System Management Support Center will provide supplies and personnel to support, monitor and manage the ISO’s subsystems; and 4) Security Services will provide a security risk assessment to the ISO regarding the security of its applications and a centralized server security system.

Third, the ISO Alliance Maintenance Contract (comprised of ABB Control Systems, Perot Systems and Ernst & Young) has three functions.  The SI/SA System (from ABB) provides the information management services needed by the scheduling system to collect, validate, store, transfer, archive and audit the energy and ancillary services schedules nominated or accepted by the ISO from Scheduling Coordinators.  The Congestion/Transmission Management Software (provided by Perot Systems) will assist the ISO in managing congestion and in determining the transmission price associated with the use of congested inter-zonal transmission paths.  The Balance of Business Systems (BBS) (provided by Ernst & Young) contract provides support for the settlements billings and the accounting and administrative functions associated with the ISO’s daily operation. 

Fourth, the UTS Meter Data Acquisition Contract will enable the ISO to collect metering data from all generators and others connected directly to the transmission lines, tie points and zonal interface points.  The ISO’s Meter Data Acquisition Contract supports the infrastructure which includes metering standards, data servers, interface equipment, databases and software to allow the ISO to collect metering data. 

Finally, the ISO’s third party vendor costs include an amount for miscellaneous communications equipment and services, including, among other things, pagers, calling cards, long distance service, cellular service, 800 numbers, conferencing, web site administration, new telecommunication equipment, remote access services and equipment (modems and modem pools), and data and voice drops.  In addition, Third Party Vendor costs include amounts for usage above the baseline quantities provided in both the MCI and IBM contracts and for certain pass-through costs that are not included in the baseline contracts (e.g., taxes).  Depending on how the services are used, the costs may vary significantly. 

Professional/Consulting/Legal 

	The Professional and Consulting Services line item ($5.615 million) in the Operating Budget consists of costs related to technical consulting services, including information technology and management consulting services; employee compensation and benefits consultants; and consultants to assist the ISO in carrying out its tariff responsibilities, such as conducting planning studies, maintenance testing, operations audits and preparation of the emergency preparedness manual.  CAS-2 at 8.  These costs also include expenses for consulting services related to the ISO’s market surveillance responsibilities such as the development of a market surveillance plan and scheduling data analysis to mitigate market power.  The Legal, Regulatory and Consulting line item ($5.5 million) consists of the projected legal and regulatory expenses necessary to carry out the ISO’s regulatory responsibilities in 1998.  CAS-2 at 9.

Other

The “other” line item in the Operating Budget ($2.124 million) includes costs related to board member compensation, materials and supplies, printing, publications, field personnel vehicles, advertising, miscellaneous hardware and software, off-site storage, and bank operating expenses.  CAS-6, workpapers at 8, 11, 13, 15, 17, 18.

Contingency

	The last item listed in the Operating Budget represents a projected contingency amount of approximately 5% of the ISO’s 1998 Operating Budget.  This contingency is necessary for several reasons.  First, the ISO, as a start-up entity, has no operating history on which to base projections of future expenses.  The contingency is thus to account for expenses yet to be identified because of the ISO’s lack of operating history.  Second, the ISO is a project that is still under construction in many respects and, as such, has encountered, and will continue to encounter, unforeseen problems that will require expenditures to ensure the ISO’s ability to reliably manage the transmission grid.  Third, the contingency amount in the budget will also
help to mitigate potential liquidity problems that may arise because of the ISO’s start-up nature and not-for-profit character (i.e., no equity).  As the ISO acquires operating history and establishes an Operating and Capital Reserve Account balance, the ISO would expect the contingency budget line item be reduced or disappear.  CAS-1 at 21.

In traditional electric utility rate filings, the Commission has held that “mere contingency or catchall expenses are not permitted in cost-of-service due to their speculative nature.”    Southwestern Public Service Company, 37 FERC ¶ 63,012, at 65,101 (1986).  This principle applies, according to the Commission, because utilities have the opportunity to estimate expenditures and to include a growth/inflation factor to account for anticipated increases in costs.  Under the “test year concept,” rates are based on specific projections of expenses and operating circumstances.  “If [the utility’s] estimates [are] inadequate or excessive, the utility should bear the risk of under-or-overrecovery.”  Wisconsin Power & Light Company, 12 FERC ¶ 63,059, at 65,247 (1980).	

Here, however, the ISO is unlike a traditional electric utility.  First, because of its start-up nature, the ISO does not have an operating history on which to base it future costs.  Thus, the ISO’s operating cost projections are more unreliable than other utilities’ Period II costs of service, which simply escalate current costs to project future costs.  Second, unlike other utilities, the ISO is a non-profit organization and will not have shareholder equity.  If, for any reason, the ISO has unforeseen expenses, it will not have equity funds to cover those expenses and will be forced to seek short-term debt financing, at additional cost, to cover any shortfall in revenues.  If forced to seek short-term debt to meet expenses, the ISO’s costs will increase to the detriment of all transmission users. See Bonneville Power Administration, 39 FERC ¶ 61,078, at 61,207-08, (BPA allowed to include amounts in rates for unforeseen contingencies and to anticipate sales and revenue underruns in the development of its rates to enable it to make timely repayments of its debt necessary to avoid interest rate penalty) order denying reh’g, 40 FERC ¶ 61,069 (1987).  If, on the other hand, the ISO has excess revenues the excess will simply be treated as revenues

for the next period’s operating budget, which may reduce the next period’s charges.  In short, the ISO cannot bear the risk of underrecovery or, for that matter, the benefit of overrecovery. 

The ISO is a start-up entity, similar to the pipeline certificate projects for which this Commission routinely approves budget contingencies.  See e.g., Northern Border Pipeline Company, 80 FERC ¶ 61,150, at 61,610 (1997) (a $50 million contingency (6.2%) approved in a construction project cost projection of  $796.8 million for inclusion in rates); see also Northern Border Pipeline Company, 11 FERC ¶ 61,088, at 61,174 (1980)(a 5-7% cost estimate contingency is normally included in pipeline cost estimates for “anticipated unknown events”); El Paso Natural Gas Company, 5 F.P.C. 115 (1946)(3.5% contingency fund in financing for construction project is consistent with the public interest)

In Iroquois Gas Transmission System, 52 FERC ¶ 61,091, at 61,349 (1990), Iroquois proposed to include in its rate base more than $21 million (approximately 5%) in cost contingencies for a project for which Iroquois had requested a construction certificate.  Intervenors objected to the inclusion of the contingency costs until Iroquois made a detailed showing of the nature of the expenses.  The Commission found that Iroquois’ proposed contingency of 5% was typical of contingencies routinely approved by the Commission:

We note that a contingency allowance of 5 percent or more has been included in costs filed by approximately 80 percent of the interstate pipelines which have sought certificates for construction before this Commission and have been allowed.  A company includes these costs to cover any overages that may be experienced by increases in cost of materials, labor, or other costs.  In the case of Iroquois, we believe that the amount requested is within an allowable zone of reasonableness.

Id. at 61,392, n.158.

In another context, the Commission has found that hydroelectric project cost estimates should include a sum for contingency costs.  Rivers Electric Company, Inc., 62 FERC ¶ 61,232 at 62,568 (1993) (project cost estimate of $1.4 million included a $250,000 contingency line item
(17.8%), which the Commission found was reasonable); Town of Springfield, 14 FERC ¶ 61,103, 61,188 (1981) (in license application proceeding, the Commission found that a project cost estimate with a 25-30% contingency was more appropriate than a 15% contingency amount); Power Authority of the State of New York, 20 FERC ¶ 63,001, at 65,007 (1982) (ALJ approved license to construct project with a “substantial contingency line item in its cost estimates”).  Although these costs were not directly included in rates and passed on to consumers, these hydroelectric cases show that reasonable cost estimates for start-up projects include contingency cost estimates.  

Thus, there are several bases on which to support the justness and reasonableness of a 5% contingency in the ISO’s projected budget: 1) the cost projections are not based on an established operating history; 2) the non-profit nature of the ISO means that it will not have equity funds to absorb revenue shortfalls; and 3) the ISO, as a start-up entity, is no different than a new pipeline or hydroelectric project for which the Commission allows reasonable development-type contingencies. 

3.	Tax Status

The ISO will be filing an application for tax-exempt status under section 501(c)(3) of the Internal Revenue Code.  If the ISO is successful in obtaining tax-exempt status under section 501(c)(3), it will not have to pay federal or state income taxes.  Thus, the ISO’s budget does not include a provision for income tax liability.  The ISO will, however, still be responsible for payroll, sales, and property taxes.  CAS-1 at 23. 
	
If the ISO obtains tax-exempt status under section 501(c)(3), the ISO may be able to issue tax-exempt bonds, which will reduce the ISO’s financing costs by approximately $4,000,000.   However, the ISO does not expect a ruling on its tax-exempt status until 1998.

DESCRIPTION OF RATES

The ISO proposes to charge each Scheduling Coordinator using the ISO Controlled Grid a Grid Management Charge (GMC) based on the metered load of that Scheduling Coordinator.  The GMC is a formula rate designed to recover the cost of operating the ISO, including operating costs, financing costs and an amount to fund an operating reserve account.  CAS-4, Schedule 1. 
 
The GMC will be based on the projected annualized costs and volumes with an annual adjustment to reflect the difference between actual and projected costs and volumes.  The formula will also contain a mechanism whereby the GMC will be reviewed each quarter and recalculated if the projected volume estimate, on an annualized basis, changes by 5% or more.    

The ISO has selected this formula rate methodology to provide Market Participants with the financial security of a predictable GMC charge and to ensure that the ISO will be able to recover its actual costs on a timely basis.   

In addition, a portion of the ISO’s costs associated with the MCI Communications Contract will be directly assigned and billed on a monthly basis to “Communication Subscribers (CS)” -- entities that are connected to the ISO’s communications network.  The projected revenues from this charge (CS Charge) will be credited to the ISO’s revenue requirement and reflected in the calculation of the GMC for the same year.  See CAS-2, Schedule 1.

The ISO will “pass-through” to customers charges for ancillary services in accordance with ISO Tariff Sections 2.5.27 through 2.5.27.4 and 2.5.28 through 2.5.28.4.  With respect to Voltage Support and Black Start Capability, the ISO proposes to charge the ISO’s cost, based on market bids for the short-term and long-term contracts that it procures for these services.  

	The ISO will charge customers Usage Charges for inter-zonal congestion and a Grid Operations Charge for intra-zonal congestion, which will be a pass-through of the bids and/or adjustment bids the ISO receives in the bidding process under ISO Tariff Sections 7.3.1 and 7.3.2.  

Finally, the ISO will pass-through charges for customers engaging in Wheeling Out and Wheeling Through transactions, in accordance with ISO Tariff Section 7.1.4.  These pass-through charges will be based on the Participating Transmission Owner (PTO) Access Charge at the point the power exits the ISO Controlled Grid.  

1. 	Grid Management Charge (GMC) 

The GMC will consist of two types of charges: 1) a Communications Subscriber Charge (CS Charge), which applies to all entities that are connected to the ISO’s data communication network; and 2) a volume-based charge, which applies to all Scheduling Coordinators based on their metered demand. 

Communications Subscriber Charge

The CS Charge component of the GMC will potentially recover a portion ($7.705 million) of the MCI Communication Contract and assign those costs to entities that are connected to the ISO’s data communication network.  The communications network is capable of accommodating 2000 Communication Subscribers of various service classes.  Each service class level will have a different monthly rate depending on the size and type of connection.  In 1998, the ISO projects that it will have a total of 200 Communications Subscribers, but until service applications are submitted, the ISO will not know their service class.  Thus, for the 1998 GMC, the ISO estimated the revenues from the CS Charge to be $770,000 or 1/10th of the total $7.705 million.  The projected revenues from the CS Charges have been credited to the revenue requirement in calculating the GMC for 1998.  CAS-1 at 42.
	
Volume Based Charge 

The components of the volume-based portion of the GMC as set forth in ISO Tariff Section 8.2 are: Start Up and Development Costs (which the ISO has included in the financing costs); Operating Costs; Financing Costs; Operating and Capital Reserve Costs.  These components are discussed in detail below.

Operating Costs
	
	Operating costs include all of the ISO’s operating costs for carrying out its responsibilities under the ISO Tariff.  These costs include salaries, benefits and incentive programs for employees, costs of operating, replacing and maintaining ISO systems, lease payments on ISO facilities, and reasonable contingencies. 

An estimate for an Annual Charge assessment was not included in the cost of service for the ISO because it was assumed that the Access Charges for the individual Participating Transmission Owners – PG&E, SDG&E and SCE – include Annual Charges.  If the ISO were to include a projection for Annual Charges in its cost of service, customers would be charged twice for Annual Charges on the same transmission.  

Financing Costs

The ISO’s financing costs are comprised primarily of the debt service for the financing of Start-Up and Development costs and future capital expenditures.  As discussed above, the Start-Up and Development costs consist of the approximately $155,163,000 of costs incurred through 
December 31, 1997, including equipment purchases, trust administration expenses, consultant and legal fees, salaries, facility construction, the hardware and software for the Power
Management System, the Scheduling Infrastructure, the Scheduling Application and the Balance 

of Business Systems.  This amount also includes the meter and data acquisition and communications infrastructure and leasehold improvements for the primary and satellite centers.   
A portion of the Start-Up and Development costs, such as the trust administration expenses, consultant and legal fees and salaries, a total of $33,222,000, have been booked to Account 301 Electric Plant Organization.  The Account 301 start-up costs are included in the $155,163,000 to be financed with the ISO’s bond issuance.

	Because the ISO is using a debt coverage model for developing its GMC, depreciation expenses are not taken into account in developing the GMC.  Instead, the GMC revenue requirement is calculated to recover an amount needed to service its debt and to fund the Operating and Capital Reserve Account. The debt service expense used to calculate the GMC includes the expense to cover the debt related to the AC 301 start-up costs.  

	As Ms. McDonald explains in her testimony, the ISO will have to comply with various bond covenants when it issues bonds to finance its start-up costs.  SSM-1 at 14.  A likely covenant will be a requirement that the ISO receive enough revenues to cover its debt service expenses by at least 1.25X.  This means that the GMC revenue requirement must recover sufficient revenues to cover the ISO’s operating costs plus 1.25 times the debt service costs.

	A debt service model to recover the ISO’s cost of service is a just and reasonable method for setting the GMC for several reasons: 1) it ensures that the ISO will recover its costs of operating; 2) it does not add non-cash items, such as depreciation, from the ISO’s cost of service
service calculation; and 3) it provides for both upward and downward adjustments in all of the ISO’s operating and debt service costs.  See, e.g., Middle South Services, Inc., 13 FERC ¶ 63,032 (1980).    

Operating and Capital Reserve Costs
	
	The Operating and Capital Reserve costs, set by the Board of Governors at 15% of the current year’s operating budget, will be maintained in a reserve account in accordance with ISO Tariff Section 8.5.  When the account is fully funded, excess funds will be swept from that account and used to reduce the following year’s GMC revenue requirement.  
	
	This reserve is necessary because the ISO has no operating history on which to base it operating budget for 1998.  This reserve account will smooth the difference between projected and actual costs, at least during the initial years of operation.  It can also be used for cash-funded capital expenditures.

	The reserve account will also provide the mechanism through which the difference (positive or negative) between the ISO’s actual and forecasted costs will be included in the next year’s GMC revenue requirement.  For example, if the ISO has excess revenues in one year, the excess revenues will flow into the operating and reserve account.  When the account is fully funded (i.e., equal to 15% of the prior year’s operating budget), the amount over and above the 15% will be swept from the reserve account and treated as revenues that will be credited to the GMC revenue requirement for the following year.  Initially, the ISO expects that it will take three years to fully fund the reserve account.  SSM-1 at 15.  

Transmission Volumes

The GMC rate is calculated by dividing the annual projected operating, debt service and reserve costs, as discussed above, by the projected annual volumes.  The projected annual volume estimate used to develop the 1998 GMC consists of 1) the volume of power transmitted through the ISO by the three IOUs, which includes all power, for either bundled UDC customers or direct access customers using the Grid (179,239 GWh); 2) the volume transmitted for others by the IOUs under existing contracts (26,269 GWh); and 3) the projected amount of wheeling through the ISO Grid (2,330 GWh).  The total volume estimated by Mr. Seabron Adamson of London Economics and used in calculating the GMC is 208,000 GWh (or 208,000,000 MWh). SCA-2.   

  Although some publicly-owned utilities (in addition to the IOUs) may choose to participate, they have not yet agreed to do so.  Therefore, as a conservative estimate, ISO volume projections used to calculate the GMC do not include these potential volumes.  SCA-1 at 12.  Should other entities join the ISO during 1998, the GMC formula allows the volume estimate to be adjusted on a quarterly basis, if the change in volumes, on an annualized basis, is 5% or greater.

Using 208,000,000 MWh as the denominator, and the ISO’s revenue requirement as the numerator, the GMC rate is calculated as follows:

Development of Grid Management Charge

			    		   		   	1998				
Revenue Requirement				  $152,710,000	
Transmission Volume (MWh)		    208,000,000	
Grid Management Charge ($/MWh)	     	       $ 0.7342		

With a Grid Management Charge of $0.7342/MWh, a +/- 30,000,000 MWh change in the volume will have an approximate effect of +/- $0.1 on the Grid Management Charge.  Likewise, a +/- $20,000,000 change in costs will affect the Grid Management Charge by approximately +/- $0.1.

Annual Adjustment

By operation of the GMC formula, the GMC will be adjusted annually to ensure that the GMC does not overrecover or underrecover ISO expenses over time.  The annual adjustment will modify the GMC for a surplus or deficit in operating revenues from the previous year.  When 

necessary, excess funds will be retained until the Operating and Reserve Account is fully funded to 15% of the previous year’s operating budget.  The GMC will be adjusted on a prospective basis only. The ISO has selected this formula rate methodology to provide Market Participants with the financial security of a predictable charge for the GMC and to ensure that the ISO will be able to recover its actual costs on a timely basis.     

The annual adjustment will also project new volumes for the denominator and correct prospectively for any differences in actual versus projected volumes in the previous year.  The formula will also contain a mechanism whereby the GMC will be reviewed each quarter and recalculated if the projected volume estimate, on an annualized basis, changes by 5% or more.  Thus, if new entities join the ISO mid-year, the GMC can be lowered on a quarterly basis.

When the Commission accepts a formula rate as a filed rate it grants waiver of the filing and notice requirements of Section 205 of the FPA.   Alabama Power Company, 993 F.2d 1557, 1568 (D.C. Cir. 1993).  A formula rate allows a utility’s rates to change repeatedly without notice to the Commission, provided those changes are consistent with the formula.  Id.; see also San Diego Gas & Electric Co. v. Alamito Co., 46 FERC ¶ 61,363, at 62,114 (1989).  Rates could increase or decrease without being subject to a Section 35 filing.  Alabama Power Co., 993 F.2d at 1567.  This procedure allows utilities some relief from regulatory burdens.

The ISO respectfully requests waiver of the filing and notice requirements of Section 205 to the extent necessary to implement its GMC formula rate.  The ISO proposes to file with the Commission, for informational purposes, its GMC rate calculated pursuant to the GMC formula on an annual basis.  The ISO as a nonprofit corporation, has no incentive to inflate its costs.  Nevertheless the accuracy of the ISO’s costs can be verified by a Commission audit.   See  Alabama Power Co.  993 F.2d at 1568 (petitioners agreed to file with the Commission informational schedules detailing annual cost projections, to ensure that its rates were consistent with the formula).

The use of a formula rate is particularly appropriate here because the GMC formula will allow both upward and downward adjustments to the GMC rate.  See Louisiana Public Service Commission v. FERC, 688 F.2d 357, 360 (5th Cir. 1982), cert. denied, 460 U.S. 1082 (1983).  This will ensure that transmission users will pay only for actual increases and decreases in costs.  Id.     

Allocation

The GMC rate will be charged to all Scheduling Coordinators in accordance with ISO Tariff Section 8.3.  Each Scheduling Coordinator’s GMC will equal the GMC rate times the Scheduling Coordinator’s metered demand, which will be available 65 days the end of the month in which service was provided.  The GMC will be billed to Scheduling Coordinators on a monthly basis, in arrears, based on metered volumes. 

A policy issue that is not resolved in this filing is whether load located in the ISO’s control area but not scheduled through the existing control area operator should be charged the GMC.  The ISO Board of Governors agreed not to take a position on this issue.   However, should the Commission decide such an exemption is warranted, the exemption should be limited to existing arrangements and should not apply to similar arrangements in the future.  The consequences of providing an exemption to such future arrangements will be to skew Market Participants’ decision-making toward options that avoid the GMC.  This will potentially lead to smaller and smaller amounts of load paying the GMC.  It will also lead to inefficient resource allocation because it optimizes one Market Participants’ result and sub-optimizes the result for the market as a whole.  

2.	Pass-Through Charges

Ancillary Services

Transmission customers using the ISO Grid must either self-provide or purchase the following ancillary services: Regulation Service, Spinning Reserve Service, Non-Spinning Reserve Service, and Replacement Reserve Service. The ISO will settle charges for all ancillary services that are not self-provided based on the cost of the service to the ISO.  Charges for these services will be determined through the ancillary services auction as provided in ISO Tariff Sections 2.5.27 through 2.5.27.4 and 2.5.28 through 2.5.28.4, and passed on directly to customers who do not self-provide these services.  CAS-4, Schedules 4, 5, 6 and 7. 

Transmission customers must purchase from the ISO Voltage Support Service and Black Start Capability.  These two services cannot be self-provided.  Charges for Voltage Support and Black Start Capability will be based on the cost the ISO incurs in contracts with service providers.  CAS-4, Schedules 3, 8.  The ISO’s costs will be passed directly to transmission customers.  The Voltage Support charge will be based on the ISO’s long-term and short-term contracts for Voltage Support service in accordance with ISO Tariff Section 2.5.27.5.  CAS-4, Schedule 3.  The ISO is currently negotiating contracts for Voltage Support and Black Start Capability.    

Scheduling, System Control and Dispatch Service is one of the six services required in Order No. 888, but is not included as separate ancillary service in the ISO tariff.  The ISO’s function is to provide scheduling, system control and dispatch services for the entire ISO Grid.  The costs associated with this service are the ISO’s operating costs and will thus be recovered by the ISO through the Grid Management Charge and not as a separate scheduling charge.  
Congestion Charges

The ISO Tariff (Section 7.3.1) provides that the ISO will impose a Usage Charge on transmission customers using a congested inter-zonal transmission path.  This charge will be determined by the ISO’s inter-zonal congestion management process in ISO Tariff Section 7.2.5.  CAS-4, Schedule 11.  The Grid Operations Charge (ISO Tariff Section 7.3.2) will be imposed by the ISO on transmission customers using a congested intra-zonal transmission path.  The Grid Operations charge will be determined by the ISO’s intra-zonal congestion management process in Section 7.2.6.  CAS-4, Schedule 12.  Because these congestion charges are merely passed through by the ISO to the highest bidder for the service, there are no specific rates in the rate schedules for these charges.  

Imbalance Energy Charges 

Imbalance Energy Charges consist of charges for Imbalance Energy, dispatched Replacement Reserves, and Unaccounted for Energy.  Imbalance Energy is the real time change in generation or demand that is instructed by the ISO to maintain the ISO Controlled Grid in accordance with the applicable reliability criteria.  CAS-4, Schedule 9.  The charge for dispatched Replacement Reserves applies when Scheduling Coordinators’ generation falls below their load or loads exceed schedules.  Unaccounted for Energy is the difference between energy delivered into a service area and the total metered demand in the service area (adjusted for losses) attributable to meter measurement errors, power flow modeling errors, energy theft, statistical load profile errors and distribution loss deviations. 

The charges for these services all fall under the ISO’s Energy Imbalance Charge rate schedule.  CAS-4, Schedule 9.  Energy Imbalance Charges will be calculated in accordance with ISO Tariff Section 11.2.4.1 and will be based on the Hourly Ex Post Price for energy during the settlement period.  Scheduling Coordinators may also either self-provide or purchase from the ISO Transmission Losses at the Hourly Ex Post Price for Imbalance Energy.  ISO Tariff Section 7.4.1.2.          
 
Access Charges/Wheeling Access Charges 

An Access Charge is basically a transmission rate.  The Access Charges for transmission on the ISO Controlled Grid have been developed by each Participating Transmission Owner (PTO) based on each PTO’s transmission service revenue requirement.  PG&E Docket No. ER97-2358, SCE Docket No. ER97-2355, and SDG&E Docket No. ER97-2364.  Each non-PTO customer will be charged the Access Charge for the PTO where the power exits the ISO Grid.  The Wheeling Access Charges will likewise be based on the Access Charge for the utility where the power exits the ISO Grid for wheeling out or wheeling through transactions.  Access Charges will be charged to transmission customers directly by the PTOs.  Wheeling Access Charges will be passed through by the ISO in accordance with ISO Tariff Section 7.1.4.  CAS-4, Schedule 13.  Because the ISO is merely passing through the Access Charges and the Wheeling Access charges developed by the PTOs, there are no specific rates for these services in the ISO’s rate schedules.  

Reliability Must-Run Charge

The Reliability Must-Run Charge is based on the cost for generation that the ISO determines is required to be on line to meet the applicable reliability criteria requirements. The ISO will enter into contracts with generators giving the ISO the right to call on the generator to generate energy and/or provide ancillary services when necessary to ensure the reliability of the ISO Controlled Grid.  The ISO will recover the costs of Reliability Must-Run Generation from the utility that is a party to the Transmission Control Agreement in whose service area the Reliability Must-Run Generation is located.  The charge will be determined in accordance with ISO Tariff Section 5.2.7.  The ISO is currently negotiating the Reliability Must-Run Contracts.  CAS-4, Schedule 15.

3.	Other Charges

Application Fee

The ISO will charge a nonrefundable application fee to scheduling coordinators that submit a completed Scheduling Coordinator application form under ISO Tariff Section 2.2.4.1.  The application fee is $500 and is based on the ISO’s average cost of processing the application forms.  CAS-1 at 47.  The ISO expects approximately 14 applications for service in 1998.  The projected revenues from the application fee have been credited to the revenue requirement in calculating the GMC.

Charge for Failure to Follow Dispatch Instruction

If a Generating Unit, Load or System Resource fails to respond to an ISO dispatch instruction, the ISO can charge the Generating Unit, Load or System Resource for the difference between the Generating Unit’s, Load’s or System Resource’s instructed and actual output or demand at the Hourly Ex Post Price.  This charge will be calculated in accordance with ISO Tariff Section 2.5.22.11.  CAS-4, Schedule 14. 

OTHER FILING REQUIREMENTS

	No expenses or costs included in this rate filing have been alleged or judged in any administrative or judicial proceeding to be illegal, duplicative or unnecessary costs that are demonstrably the product of discriminatory employment practices.  

	The ISO is serving a complete copy of this filing on the service list in Docket Nos. EC96-19-001 and ER96-1663-001.

REQUEST FOR WAIVERS

The ISO respectfully requests a waiver of any additional requirements needed to allow the proposed rates to go into effect on January 1, 1998.

		Very truly yours,

							Jeffrey D. Tranen
Chief Executive Officer,
California Independent System
Operator Corporation

Ray S. Bolze
Stephen Angle
Linda L. Walsh
Howrey & Simon