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HomeMy WebLinkAboutMinutes - March 30, 1999 SS221 CITY OF LODI INFORMAL INFORMATIONAL MEETING "SHIRTSLEEVE" SESSION CARNEGIE FORUM 303 W. PINE STREET TUESDAY, MARCH 30, 1999 An Informal Informational Meeting ("Shirtsleeve" Session) of the Lodi City Council was held Tuesday, March 30, '1999 commencing at 7:00 a.m. ROLL CALL Present: Council Members — Hitchcock, Mann (left at 7:40 a.m.), Nakanishi, Pennino and Land (Mayor) Absent: Council Members — None Also Present: City Manager Flynn, Deputy City Manager Keeler, Community Development Director Bartlam, Finance Director McAthie, Electric Utility Director Vallow, City Attorney Hays and City Clerk Reimche Also present in the audience was a representative from the Lodi News Sentinel and The Record. TOPIC(S) 1. Electric Utility Competition Transition Plan ADJOURNMENT No action was taken by the City Council. The meeting was adjourned at approximately 8:20 a.m. ATTEST: %- Alice M. Rei the City Clerk ELECTRIC UTILITY DEPARTMENT Ci41 i Memorandum TO: Honorable Mayor Councilmembers City Manager Deputy City Manager City Attorney Finance Director FROM: Electric Utility Director DATE: March 29, 1999 SUBJECT: Competition Transition flan The following is an excerpt (in draft form) from what has been referred to as the Electric Utility's Competition Transition Plan. The attached document contains a competitive analysis which Electric Utility staff is comfortable with. The focus is clearly on the existing financial position of the Electric Utility and on certain recommendations to better position the Electric Utility for future competition. If the Council and City management accept the findings, the remaining pieces can be completed including a refined marketing plan, strategic initiatives, and organizational modifications. You will note an absence of an executive summary. After months of analysis and modifications, we believe that the simplicity of the results warrants a full understanding and buy -in of the approach taken. We hereby submit the following competitive analysis to you for your consideration and hopefully your favorable response. Competitiw Analysis In order to maintain market share and profitability, a successful business must maintain a high level of customer satisfaction and hence, must maintain a high degree of customer focus. No one doubts the wisdom of this time honored paradigm; however, a successful business strategy must look beyond singular paradigms and instead maintain focus on a broader basis. A successful business strategy must simultaneously balance the complex interactions among the customer, the competition and the internal organization. A balanced strategy approach requires constant testing and evaluation. As customers' needs change or competitive threats emerge, the organization must respond quickly to reestablish dynamic balance. In terms of the developing competitive electric utility environment, the City of Lodi Electric Utility is a market follower, not a market maker. From an overall market perspective, the size of Lodi's operations is a disadvantage from an economies of scale standpoint; however Lodi does possess a number of identifiable strengths which will serve to assist in further developing an established niche market. Those strengths include: > A well defined customer base in terms of both geographics and demographics. > An existing relationship with customers on a full service basis. Non -generation related costs and overheads which are extremely low compared to regionally comparable services. Goals Requisite to the development of a successful competitive strategy, a well formed set of strategic goals need to be developed. All actions taken to transition into a more competitive mode of operation should further one or more of the established goal set. For purposes of the City of Lodi's Electric Utility's transition into a competitive utility environment, the appropriate goal set must be robust enough to capture the full spectrum of utility operations from customer service and maintenance to financial planning. The later forms the focal point of a sound business strategy considering the transition is from a monopoly to a competitive environment. Without a solid, well developed financial plan, none of the following goals are attainable: Maintain a cost of service structure, which is regionally competitive. Provide services at "best of industry" levels. Maintain a high rate of return to the community. Adopt "best of Industry" business practices. AB 1890 In September of 1996, the California Legislature passed a landmark reform bill which fundamentally changed the way the electric utility industry would conduct business in the future. The bill had numerous, sweeping provisions all of which were intended to foster economic growth within the State. The intent of AB 1890 was to force a transition of the electric utility industry from a vertically integrated monopoly structure to a competitively based, market driven provider of energy services. One of the most significant changes that has occurred in the electric industry is the rapid shift from the traditional vertically integrated electric utility to stand alone business units. Traditionally, generation, transmission and distribution services were provided by a single corporate entity. Today, each of California's three investor owned utilities has adopted a corporate/subsidiary structure with a clear delineation between regulated and unregulated business units. The only discemible utility function remaining on a regional basis is distribution services. Deregulation brings with it the prospect that a customer will have the choice of either continuing to receive electric service on a traditional bundled basis or purchase certain pieces of that service from a variety of providers on an "unbundled" basis. With these types of choices becoming available in the market place, the means by which an existing electric utility, like Lodi's, compares its competitiveness has become considerably more complicated. For Lodi, it is no longer appropriate to measure competitiveness using bundled services measures alone. Competitiveness must also be measured on an unbundled services basis - services which are being provided by not just PG&E, but by numerous other market participants. To further ,complicate the issue, Lodi's electric operations, like other municipally owned electric systems, will remain a vertically integrated provider of ;services. Lodi will not be able to create a true subsidiary corporate structure and will forgo the strategic advantages inherent in a separate unregulated business unit. Benchmarks A competitive analysis of Lodi's electric operations with respect to appropriate competitive benchmarks needs to be conducted before a definitive action plan can be implemented. Electric rates have typically been used as competitive benchmarks. In the past, the common practice was to compare electric utility rate schedules on a regional basis. In Lodi's case, a comparison to PG&E's electric rate schedules was deemed appropriate since the PG&E area essentially surrounds Lodi. This type of comparison presented a clear picture and a sound foundation by which competitiveness could be determined on a customer -by -customer basis. Similarly, most electric consumers purchased their electric service from their local or regional power company and paid a rate for that service based on how much of the service was consumed. Few consumers knew or cared how the rate they paid was allocated among various utilities cost centers. Of interest was the total rate being paid for the "bundled" services being provided. Competition Redefined Regardless of a customer's ultimate choice, it is presumed that all customers will continue to make decisions with respect to service provider options in terms of total final cost for a given level of service. Lodi's future competitiveness from a customer's standpoint will be based on costs associated with the same services provided to others on a regional basis by the "next best competitive alternative". That is, if a customer shopped around regionally and chose various unbundled services from the lowest cost suppliers of those services, what would the lowest possible total cost be to that customer? An accurate assessment of Lodi's ability to compete on such a basis is entirely dependent on the cost structure of Lodi's existing services to the extent they can provided on a similar unbundled basis. Objective - Maintain a total final cost of electric service to the customer which is competitive with a customer's next best regional alternative. 3 Unbundled Services Unbundling of services refers to the breaking apart of the traditional "all in" electric rate into its various component parts. In its most basic form, an electric rate can be broken down into three primary components - generation, transmission and distribution. Each of these three components can be further broken down into smaller components. Unbundling of electric services has not only redefined the ratemaking concept; it has also fundamentally redefined who the competition is. It is no longer entirely accurate to benchmark an electric rate against a published regional electric tariff. Generation services are now available from a variety of third party sources and transmission service has largely been taken over by the California Independent System Operator (ISO). Costs associated with generation are market driven and costs associated with transmission is federally regulated. Distribution related costs are regulated. either by the state (for the IOUs) or locally (for municipal utilities and districts). From this point forward, any comparison of Lodi's costs to any given competitive benchmark must be done on an unbundled services basis: Lodi's Cost For Competitive Benchmark Distribution PG&E Distribution Generation Market Cost of Power Transmission California ISO As discussed previously, Lodi currently provides electric services to its customers on a bundled services basis. In order for Lodi's customers to purchase any competitive services from third parties, it will be necessary for the City Council to adopt an unbundled schedule of services. The degree to which any aspect of electric service is unbundled and the time line in which the unbundling is introduced is largely at the discretion of the City Council. Providing electric services on an unbundled basis is a significant policy level decision. AB 1890 has imposed few limiting requirements with respect to a municipalities' authority in this regard. Electric utility staff believes that an appropriate infrastructure and cost structure can be in place by mid year 2000. The following policy action is therefore recommended: That the City Council adopt an unbundled rate schedule which will allow all customers to purchase generation related services from third party providers no later than July 1, 2000 — Target date of January 1, 2000. 4 Developing Competitive Benchmarks The objective is to provide traditional electric service to the customer on a competitive cost basis and to ensure customer loyalty through the types and quality of services provided as compared to other readily available alternatives. Competitive benchmarks must be developed in terms of unbundled traditional services. Once a benchmark for each component of electric service is developed, a direct comparison to Lodi's component costs can be made. The comparisons of interest will include total final cost to the customer on both a bundled and unbundled services basis. For this purpose, a model has been developed by Henwood Energy Services (Henwood) which allows every component of electric service cost to be detailed for each customer class within the region currently served by PG&E. These costs have been projected through the year 2015 which is the planning horizon currently. being used by Lodi. For benchmarking purposes, the rate projections are broken down by both customer class and by rate component. Each rate component for each customer class can then be allocated to the three major cost centers: generation, transmission and distribution. Appendix A contains a more thorough analysis of the modeling technique and base case assumptions. Comparing Costs Cost comparisons can be made down to the level of an individual custpmer on the basis of the same service being provided by the "next best competitive alternative". From a policy perspective, however, customer class rate equity is somewhat less interesting at this juncture than the overall financial health and competitive posture of Lodi's electric operations - Customer class rate equity depends on a sound financial base. The Henwood model provides the basis by which Lodi's existing cost structure can be compared to a utility operation using costs associated with the lowest cost regional competitive alternative. City staff has chosen to use an approach, which establishes maximum revenue that can be supported in a competitive environment. Comparing maximum competitive revenues with projected costs allows for direct analysis of the underlying cost and capital structure of the electric operations for each of the three major cost centers -- Generation, transmission and distribution. Maximum competitive revenues are determined by multiplying the energy sales of each customer class by the next best regional competitive alternative electric rate applicable to that class and then totaling all the customer classes. The maximum competitive revenue amount is then divided by the total energy sales to yield a maximum competitive system average competitive electric rate. A direct comparison between Lodi's projected system average electric rate under its existing cost and capital structure and the maximum competitive system average rate can be made on this basis. This comparison gives a very general indication as to the underlying competitiveness of the existing "base case" financial structure (Figure 1). From this point, each of the three major cost centers can be compared in a similar fashion (Figures 2,3 & 4). This same `•analytical approach can be made on a customer class or an individual customer basis. Appendix B contains a detailed analysis of Lodi's current and projected operating results through the year 2015 given its existing cost and capital structure (lase Case). 5 Distribution Figure 2 illustrates Lodi's current base case distribution system costs on the same basis as PG&E's distribution system costs. The classical definition of distribution costs has been modified to include all costs, which a distribution system customer is responsible for. The summation of all such costs are referred to as "Distribution and other non -bypassable costs. These costs include traditional distribution system costs plus other costs such as CTC, nuclear decommissioning, power purchase contracts, public benefits program charges, etc. These costs are either allowed or mandated by AB 1890 as appropriate customer charges, which a customer must pay as a condition of being connected to a utilities distribution system. Self -generation by a customer will not preclude the application of these costs to the extent the customer maintains a physical connection to the local distribution utility. Transmission Figure 3 illustrates Lodi's current base case transmission costs compared to a regional customer's transmission cost if they currently receive distribution services from PG&E. These costs are perhaps the least well known of any of the unbundled rate components. Currently, ISO charges have been the subject of considerable debate both within the State and at the Federal level. In addition, NCPA is currently negotiating a successor agreement to its interconnection agreement with PG&E. Federal Energy Regulatory Commission (FERC) rulings have held that transmission service must be provided on a non- discriminatory basis with terms and conditions the same for all parties. The implication here is that Lodi's distribution customers should end up paying the same for transmission service as PG&E's distribution customers. The methodology used takes a conservative approach to Lodi's forecasted transmission costs by assuming that the existing transmission cost structure will persist through the year 2010. At that time, it is likely that customers on Lodi's system will pay only ISO related charges and those costs associated with transmission quality enhancements which exceed regional quality standards. Costs associated with Lodi's proposed transmission project fall into the quality enhancement category. Generation Generation costs have been the basis for most expectations regarding the prospect of lower future electric rates. The single most important factor impacting the future competitiveness of an electric utility is the amount by which generation costs exceed the market cost of power at any point in time (stranded investment). NCPA has completed a series of refinancing transactions for the purpose of restructuring the outstanding generation debt obligations. The debt restructuring has significantly lowered the stranded; investment exposure of the project participants. The extent to which Lodi faces stranded investment exposure in the future will depend on the actual performance of the generation market over time. By the end of the;year 2010, Lodi's generation costs are expected to be near market levels. The primary focus of Lodi's generation cost strategy will, therefore, focus on the primary years of stranded cost risk 6 exposure - the year 2002 through the year 2010. In order to develop a sound stranded cost strategy, a reliable forecast of generation market costs must be available. Over the past several years, Henwood has provided what is acknowledged as perhaps the best competitive generation market forecasts. The generation market forecast used by Lodi in its competitive modeling is the Henwood "low" market forecast. Use of the low market forecast adds a level of conservatism to the calculation of stranded cost exposure. The low market forecast uses a statistical modeling approach that assumes that actual generation market levels will exceed the forecast 90 percent of the time and the market will actually be lower only 10 percent of the time. Here again, using the low market forecast is a conservative approach which would tend to overstate the magnitude of Lodi's stranded generation investment exposure- the amount by which Lodi's actual generation cost exceeds the competitive market generation price (Figure 4). In an unbundled services environment, stranded investment must be paid for out of cash reserves, free cash flow or through application of a stranded investment surcharge. AB 1890 allows for such a rate surcharge - the Competition Transition Charge (CTC). The CTC is a non -bypassable charge included in the distribution portion of an unbundled rate. For instance, a typical Lodi customer currently pays approximately 5.2 cents per kilowatt-hour for generation. In an unbundled services environment, the same customer would pay the market price for generation plus a CTC included as a distribution charge where: Lodi Generation Cost - Market Generation Price = CTC Clearly, the customer would be paying the same amount (5.2 cents per kilowatt hour) unless a third party provider can offer a generation price which is lower than the competitive market or unless the CTC is reduced by some subsidy amount (cash reserves). California's three investor owned utilities are currently charging a generation related CTC which is expected to end no later than March of 2002. Two areas of risk must be considered in development of a final strategy: Competitive Risk - California's investor owned utilities will not be charging a CTC beyond the year 2002; and > Regulatory Risk - It has been assumed that CTC can not be collected beyond the year 2010. Base Case Analysis In order to establish an action plan that assures rate competitiveness, an accurate assessment must be made in terms of Lodi's current and future costs given our current business practices. These costs must then be benchmarked to the next best competitive alternative. Figure 1 illustrates Lodi's competitive position with respect to a competitive regional alternative electric rate. The competitive rate was developed following the previously discussed methodology — the summation of PG&E distribution/non-bypassable rates, ISO transmission rates and market generation. This approach allows a system average rate comparison to be made. This comparison is important in order to assess the overall financial health of Lodi's electric operations. Caution must be exercised when making system average rate comparisons due to the high degree of variability between electric usage profiles and load shapes. For instance, two different service areas using identical electric rate schedules will have different system average rates unless the percentage of electric use for each customer class is identical. Lodi's system average electric rate is expected to be higher than most regional system measures due largely to its high percentage of residential customer use. This type of rate differential is also apparent between similar customers located in different areas. A residential customer located in a coastal climate will likely see a lower average annual rate than a customer located in the central valley due to higher summer usage in the valley. Again, the comparison made in figure 1 relates primarily to the financial health of Lodi's electric operation in a competitive rate environment. The degree to which Lodi can be competitive will depend on the relative competitiveness of each of the three major cost centers. A close look at figure 1 illustrates that Lodi is reasonably competitive on a system average rate base with a competitive advantage until the year 2002 and after the year 2010. This observation would suggest that a closer look at each of the three major cost centers is necessary in order to determine if Lodi's competitiveness in the years 2003 through 2010 can be improved. At this point, consideration must be given to the means by which Lodi can achieve competitive rate parity within the region. Going back to the previous unbundling analysis, it was noted that the most significant cost component impacting rate competitiveness is Lodi's generation costs. Little can be done prospectively to further reduce Lodi's generation costs. NCPA has completed its debt restructuring — no further savings in that regard should be expected. Operating costs associated with generation compare very favorably to industry benchmarks — significant future savings on this cost component are not expected. Implementation of a CTC and application of cash reserves are the only means by which above market generation costs can be recovered or paid for in a competitive market. Several municipal utilities have imposed a temporary surcharge on electric sales designed to build up cash reserves. By having sufficient cash reserves, the CTC component of non - bypassable charges can be avoided or minimized after the year 2002(the end of the sanctioned transition period). Another typical approach has been to cut general fund transfers and divert that revenue stream to generation debt reduction. Lodi has rejected these approaches as a first line of defense choosing instead to explore all other means to achieve a competitive rate structure. This commitment was made when rates were frozen in the fall of 1995. If no other means can be found, these remain as options of last resort. The rationale behind this decision is very simple. First, Lodi does not believe that it is in the communities best interest to impose additional rate surcharges at a time when economic growth is just beginning to return to the area. Second., Lodi's electric utility was founded on the basis of providing a source of funding for a variety'of community services related directly to local quality of life. Both rates and community benefits derived through General Fund transfers are paramount among the previously established goals. Lodi's approach to rate competitiveness should not focus on any singular aspect of cost causation. From a customer's perspective, components of cost are somewhat less important than the final, "all in" cost of service. Ultimately, even in an unbundled services world, a customer can be expected to evaluate competitiveness on a total cost basis. The challenge is to ensure that each of Lodi's cost centers is recoverable in an unbundled environment while maintaining a competitive advantage in some fashion. Lodi's generation costs will be higher than the market projection now and in the future, therefore, either a CTC or application of existing cash reserves can be used to provide for generation cost sufficiency. Transmission costs "are what they are' and do not represent a large enough cost exposure for significant competitive cost reductions. What is left is the distribution cost component and available cash reserves. This is the most reasonable place to begin a search for an alternative to the base case. Development of Alternatives Up to this point, the primary focus of the analysis has been on fulfilling the implications of the first of the stated goals - maintaining a regionally competitive cost structure. An acceptable altemative to the Base Case scenario must consider the implications of the entire previously established goal set in a manner which: Results in a rate structure that is at or below the total cost of service if provided by the next best competitive alternative. Provides flexibility for continued targeted economic development. Furthers the previously established goals in terms of service quality and return to the community. Provides maximum local control. Remains legally permissible given statutory/regulatory limitations. The method chosen in this analysis will focus on the total costs that a customer would be exposed to if services were provided in a manner consistent with the next best competitive alternative. Using this approach, a comparison can be made between Lodi's projected costs and the revenues which could be expected if capped at the level of the next best competitive altemative given the following assumptions: Lodi's current rates will be frozen through July 1, 2002. Lodi's rates will be unbundled and all customers allowed to purchase power and other available market services no later than July 1, 2000 — Target date of January 1, 2000. All customers will pay a nort-bypassable CTC through the year 2010, included in the distribution charge. > Distribution related charges will be copped at the regional competitive level - Lodi will "buy -down" total distribution costs which exceed the cap. 9 > Lodi's revenues will be capped at a level equal to the lesser of the next best competitive alternative or the maximum permissible regulatory rate beginning on July 1, 2002. The transfer to the general fund will be held to 1999 levels through the planning horizon for planning purposes. The assumptions so stated are not intended to hold a customer captive, but instead are intended to create cost indifference from both a customer perspective and a utility perspective. With generation costs tied to market levels, a customer would be indifferent as to where generation related services come from and the utility would be indifferent as to whether the customer purchased bundled services or chose to "shop around". With perceived cost indifference, customer retention will depend on each customer's perception of service quality and value of the service provided. Recent industry research into the area of customer loyalty indicates that generally, a customer will be willing to pay up to a five percent premium for a high perceived value of service. For analysis purposes, Lodi will continue to view electric service as a pure price based commodity and will not assume that a customer is willing to pay more for superior service. This adds yet another area of conservatism to the analysis. Findings The Base Case results showed that application of cash reserves alone are insufficient to "buy down" costs to the target level. In depth analysis of distribution system costs leaves open a very narrow range of options to achieve the stated objectives. From a policy perspective, the first line of scrutiny is generally costs and specifically, which costs can be cut. Traditional utility cost cutting focused on service levels and maintenance. This approach has proven to be counter productive, particularly in a competitive environment where service is the only true means of product differentiation. Deferring maintenance has a chilling effect on service reliability and hence, on business retention and attraction efforts. In Lodi's case, the single highest distribution system cost center is labor. Lodi's ranks within the top 10 percent of utilities nation wide in terms of labor costs benchmarked to virtually every meaningful measure (employees per customer, employees per dollar of revenue and labor cost to kWh sold). Labor savings in an already lean and efficient operation is not a prudent cost cutting approach. Deferring O&M costs and/or capital improvements is similarly self defeating. The only area left is the overall capital structure of the distribution system. The existing capital structure of Lodi's distribution system is relatively easy to analyze. Lodi has no outstanding debt on its distribution system. All operating and maintenance expenses as well as capital improvements have traditionally been paid for out of current revenues or reserves. The virtues associated with this practice can be debated on a number of levels and certainly justified. from the cash flow standpoint of a monopoly enterprise. Its virtues become less certain in the context of a more competitive environment. Simply stated, the expensing of capital improvements in a capital -intensive 10 competitive industry is not a prudent business practice. An equity issue can be made that long-term capital expenses should be paid for by those using the system over the life of the system and not entirely by today's customers. A counter argument can be made that debt is simply a bad thing. Lodi can not achieve a distribution system capital structure similar to its PG&E counterpart because Lodi can not offer equity interests in its physical facilities through stock ownership. Since Lodi has no outstanding distribution system debt, refinancing or debt restructuring is not an available option. Redefining Lodi's capital structure is confined to two possible alternatives - recapitalization of the existing system or the financing of future capital expenses (or a combination of both). Capital Financing Alternatives Recapitalization (Borrowing against the equity of the system) presents a number of tactical hurdles that must be overcome if this method is to be considered a cost-effective means of capital asset management. Generally, the United States Internal Revenue Code limits the extent to which tax exempt debt can be issued for the purpose of recovering past expenses to the prior 90 days. An exception to this rule applies if the municipal electric system's governing body has previously passed a "reimbursement resolution". The Lodi City Council passed such a resolution in November of 1996. The resolution was passed in order to preserve the City's ability to recover a portion of its capital expenses incurred from the date of the resolution forward. The financing of certain capital expenses was contemplated in preparation all Electric Utility budgets beginning in 1996. It is not recommended that capital cost recovery go back beyond that point. Lodi Electric Utility Staff recommends that the City Council approve the issuance of revenue bonds for the purpose of reimbursing the Electric Utility Capital Outlay Fund in an amount equal to the capital expenditures made from the date of the reimbursement resolution to the date of issuance of the bonds. The amount is approximately $6 million. There are several legitimate approaches to the handling of future capital needs. Capital Costs can be paid for out of current revenues or they can be financed. Smaller capital costs that are ongoing in nature are best paid out of current revenues, whereas, large capital projects are certainly the most likely candidates for financing. Large projects would include the recently discussed street lighting project, substation additions, new electric utility service center, transmission projects, etc. Capital financing has several distinct advantages. From a practical point of view, it is unlikely that certain capital projects will be undertaken without a capital financing. The rapidly emerging competitive environment places a functional restriction on the use ;of existing reserves and projected revenues. From an asset management point of view, the payback period can be structured in such a way as to reshape the electric utilities underlying cost structure. Such an approach could be used to lower system costs in the years 2002 through 2010 while still allowing cetain necessary projects to be undertaken. Another advantage today is the historically low interest rate environment. Again, from an asset management point of view, financing in this interest rate environment is a least cost approach to capital investement. A balanced approach using 11 both current revenues and a capital financing would seem to be the most prudent course of action. Lodi Electric Utility Staff recommends that the City Council approve the issuance of revenue bonds for the purpose of financing certain prospective capital expenditures. The amount is approximately $15 million. It is further recommended that the approval include an additional amount to complete the refinancing of a reliability based transmission system enhancement in an amount not to exceed $95 million. Analysis of Altemative Structure A look back at figure 1 reveals ample room for modifications to the cash flow requirements of the Electric Utility over the planning horizon. The proposed capital financing achieves three signifant results. First, existing cash reserves are enhanced thereby increasing the amount by which Lodi can reduce generation cost exposure. Second, by reducing cash flow requirements, the overall revenue requirement can be reduced in those years where the Electric Utility was not competitive in the base case. Third, this approach makes certain necessary capital expenditures possible. Figure 5 illustrates the results of restructuring the cash flow requirements within the distribution system by using a capital financing strategy. Competitiveness of the Electric Utility is enhanced from a cost structure standpoint and quality of service is enhanced due to the types of capital improvements contemplated. Actual costs of service for the distribution component under the proposed scenario are shown in Figure 6. It is clear that this approach moves the cost structure of the Electric Utility closer to the regional structure. This has the net impact increasing the City Council's regulatory authority and reducing unfunded cost exposure on the generation component - Figure 7. A more definitive analysis of the proposed cost structure is included in Appendix C. 12 Lodi Electric UI • Maintain a cost of service structure , which is regionally competitive O 0 w ■ � o L � = 0 Lodi Electric Ut • Maintain a high rate of return to the Community 3 §7k 7r Competitive Rate Methodology • Determine maximum revenue in a competitive environment. • Fit all costs within revenues. •Unbundle costs into 3 primary components: Generation / Transmission Distribution • Compare unbundled rates to competitive benchmarks. • Modify unbundled cost to meet or beat _ competitive benchmarks. 5 Lodi's Strengths • A well defined customer base in terms of both geographics and demographics. • An existing relationship with customers on a full service basis. • Non -generation related costs and overheads which are extremely low compared to regionally comparable services. M _ 0 J Ll U H U L a a 0 L �J N .F+ L VL c N U ■� � i o L V � V V _ 0 J Ll U H U L a a 0 L �J N d CL E 0 v 2 6me L O U. cn O 0 cn ._ ma O J ��o W oa a a. 0 Ll r � V 0 Don't Confuse Costs with Rates A Good Alternative to the Base Case is One That: • Results in a rate structure that is at or below the total cost of service if provided by the next best competitive alternative. • Provides flexibility for continued targeted economic development. • Furthers the previously established goals in terms of service quality and return to the community. • Provides maximum local control. • Remains legally permissible given statutory/regulatory limitations. Some Key Policy Decisions • Lodi's current rates will be frozen through July 1, 2002. • Lodi's rates will be unbundled and all customers allowed to purchase power and -- other available market services no later than July 1, 2000 -Targeted date of January 1, 2000. • All customers will pay a non -bypassable CTC through the year 2010, included in the distribution charge. • Distribution related charges will be capped at the regional competitive level - Lodi will "buy -down" total distribution -- costs which exceed the cap. • Lodi's revenues will be capped at a level equal to the lesser of the next best competitive alternative or the maximum permissible regulatory rate beginning on July 1, 2002. • The transfer to the general fund will be held to 1999 levels through the planning horizon for planning purposes. 17- Lodi Electric Utility Staff recommends that the City Council approve the issuance of revenue bonds for the purpose of -- reimbursing the Electric Utility Capital Outlay Fund in an amount,equal to the capital expenditures made from the date of the reimbursement resolution to the date of issuance of the bonds. - The amount is approximately $6 million )3 Electric Utility Staff recommends that the City Council approve the issuance of revenue bonds for the purpose of financing certain prospective capital expenditures. The amount is approximately $15 million. It is further recommended that the approval include an additional amount to complete the refinancing of a reliability based -- transmission system enhancement in an amount not to exceed $15 million. 11 N 0 0 O O N O w J m Q Q } m O Z Z ZO � > m Q g LU LU z W LU F— N 0 0 0 C 0 (D O O O O 00 to I -t t4 44 us 69). HMW/$ s� o� o� oz oc, ez 01- Z o1- 1 01- 60' ob. so oc� �O o� 90 011 so oc, VE, �0 be z0 0e 00 02 b'6, sZ 21 M DISTRIBUTION EXPENSES - BASE CASE $80.00 $70.00 $60.00 $50.00 x M $40.00 $30.00 $20.00 $10.00 $0.00 ,-o �o �o �o no ,yo do ,yo lip f ,yo 1yo do ,yo ,yo IV do CTC MGeneral Fund Transfer General Fund Capital Loan ®PubliC Benefits Expenses =Distribution Capital MDistribution 0&M —*—PG&E Distribution/Non-Bypassable Figure 2 January 20, 1999 Lodi Electric Utility Distribution COSTS $8.00 $7.00 $6.00 $5.00 $4.00 $3.00 $2.00 $1.00 $0.00 Electric Utility Department TRANSMISSION EXPENSES - ALL CASES 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 Figure 3 ®Interconnection COTP/SOT =Other Contracts —* PG&E January 20, 1999 $0.06000 $0.05000 $0.04000 x $0.03000 w a $0.02000 $0.01000 $0.00000 GENERATION RATES - BASE CASE 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 Lodi Electric Utility Figure 4a W:3 LODI CTC LODI GENERATION —m—MARKET GENERATION January 20, 1999 Generation RATES - Base $30,000 $25,000 $20,000 N 9 C 3 $15,000 $10,000 $5,000 $0 GENERATION COSTS - BASE CASE 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 NW::] LODI DEBT SERVICE LODI 0&M SIE -MARKET January 20, 1999 Lodi Electric Utility Figure 4b Generation COSTS - Base $120.00 $100.00 $80.00 $60.00 $40.00 $20.00 $0.00 LODI ELECTRIC RATES VS COMPETITIVE RATES - PROPOSED 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 Electric Utility Department Figure 5 ® CTC ® GENERATION TRANSMISSION DISTRIBUTION/NON- BYPASSABLE x COMPETITIVE RATE January 20, 1999 Compeitive Rates - Proposed DISTRIBUTION EXPENSES - PROPOSED $80.00 $70.00 $60.00 $50.00 $40.00 $30.00 $20.00 $10.00 $0.00 e,yo pyo pyo pyo epyo pyo le" ,yo epyo EM CTC =General Fund Transfer 10 General Fund Capital Loan Public Benefits Expenses =Distribution Capital =Distribution 0&M -- PG&E Distribution/Non- Bypassable Electric Utility Department Figure 6 Janaury 20, 1999 0 W N 0 IL 0 oc a W H a Z 0 a W Z W U 0 0 0 0 0 0 0 f0 LA sh Cl) N O O O O O O O O O O O O O O O FR 603, G03 G9 G/? ria GA HMI 2l3d S s� 02 A o� ON el 02 oe OZ 01- 60 otl 190 o�, �o o� �0z eve 'olc� 1p0 0el 6o o2 -,o oe, 000, ss s� cu LL U _N W 0 J z G) o o_ o0 Z F- N a O < m Gn a C z �ca W LL, o .0 C 7 U Z I— W F- c U ULU 6 Es O O Q� 0 0 0 0 0 0 0 f0 LA sh Cl) N O O O O O O O O O O O O O O O FR 603, G03 G9 G/? ria GA HMI 2l3d S s� 02 A o� ON el 02 oe OZ 01- 60 otl 190 o�, �o o� �0z eve 'olc� 1p0 0el 6o o2 -,o oe, 000, ss s� cu LL U _N W 0 J 0 W O CL O ad IL O u z O W Z W 0 LLI U_ W U) C w ca F- a o LU Q 0 0 2 m 00 Cl 0 CD 40 Co p O O Cl N N 69 60 69 6% Ui (spuesnotyl) M, O N Q U :V h V \I r y V O O N A V >D V D V D 7 V A 7 :V cV M 0 0 N N O O N O O N O O O N O O 61 r C O cC 0 - CD N Q U v CD LU HENWOOD COMPETITIVE RATES MODEL LODI COMPETITIVE RATE TARGET NCPA Study Unbundled Rales by Class Model5i.xls Prepared by: Hunwood Energy Services, Inc P. 1 of 3 03/20119999.37 AM Al BI C D I E I F I S I AF I AS I BF I BS I CF I CS I DF I DS I EF I ES I FF I FS 1 '97 Rate 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 (S/IviWh) Allocalor Average Avera r, Avera a Average Average Avera a Avera a Average Average Average Average Average Average 4 Residential momomim 5 Total Average Customer Charge 107.52 107.52 107.52 107.52 101.06 99.00 99.48 100.18 100.14 100.07 92.82 93.04 93.49 6 PX Price 22.78 22.90 24.63 26.51 28.52 2953 30.57 31.65 32.12 32.60 33.09 33.56 34.08 7 Ancillary Service & ISOIPX Charges 1.48 1.49 1.52 1.55 1.59 1.61 1.62 1.64 1.65 1.66 1.67 1.68 1.69 8 Line Loss Charge 2.18 2.20 2.35 2.53 2.71 2.80 2.90 3.00 3.04 3.08 3.13 3.17 3.22 9 Delivered Energy Price 26.45 26.58 28.50 3058 32.82 33.94 35.09 36.29 36.82 37.35 37.89 38.43 38.99 10 Trust Transfer Amount 16.15 11.21 12.47 11.72 11.07 10.35 9.67 8.97 8.31 7.80 0.00 0.00 0.00 11 Employee Transition CTC 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 12 Long Term Purchase Contracts (QF's) 13.60 11.03 8,00 7.58 6.53 6.31 6.09 6.06 5.93 5.60 5.37 4.60 4.45 13 Tran sitionCTC .-._.. 11.99 12.68 12.68 11.90 14 CTC's 25.59 23.71 20.68 19.48 6.53 631 6.09 6.06 5.93 5.60 5.37 4.80 4.45 15 Transmission Charge 3.39% 4.05 4.05 4.05 4.05 4.27 4,32 4.36 4.39 4.43 4.46 4.50 4.53 4.57 16 Distribution Charge 28.05% 33.51 40.21 40.09 39.98 42.02 42.41 42.62 42.83 43.05 43.27 43.49 43.72 43.95 17 Public Purpose Programs Charge 1.27 1.25 1.23 1.21 1.19 1.17 1.15 1.13 1.11 1.09 1.07 1.05 1.03 14 Nuclear Decommissionina Charge 0.43% 0,51 0.51 0.51 0.51 0.51 0.51 0.51 0.51 0.51 0.51 0.51 0.51 0.51 20 Small Light and Power 21 Total Average Customer Charge 112.85 112.85 112.85 112.85 96.87 97.44 97.88 98.55 98.47 98.37 90.75 90.95 91.38 22 PX Price 22.40 23.26 25.14 27.06 29.11 30.14 31.21 32.31 32.79 33.28 33.77 34.28 34.79 23 Ancillary Service & tSOIPX Charges 1.48 1.49 1.53 1.56 1.60 1.02 1.64 1.66 1.66 1.67 1.68 1.69 1.70 24 Line Loss Charge 2.15 2.23 2.40 258 2.76 2.86 2.96 3,06 3.10 3.15 3.19 3.24 3.28 25 Delivered Energy Price 26.03 26.98 29.07 31.19 33.48 34.62 35.60 37.02 37.55 38.10 38.65 39.21 39.77 28 Trust Transfer Amount 16.88 11.71 13.03 12.25 11.57 10.82 10.11 9.38 8.68 8.15 0.00 0.00 0.00 CTC's 33.21 30.78 27.52 26.32 6.64 6.42 6.19 6.16 6.03 5.70 5.46 4.88 4.52 31 Transmission Charge 3.22% 3.85 3.85 3.85 3.85 4.06 4.11 4.14 4.17 4.21 4.24 4.27 4.31 4.34 d30 32 Distribution Charge 28.00% 31.06 37.77 37.64 37.53 39.44 39.80 39.99 40.18 40,37 40.57 40.77 40.98 41.19 33 Public Purpose Programs Charge 1.31 1.29 1.27 1.25 1.23 1.21 1.20 1.18 1.16 1.14 1.13 1.11 1.09 Nuclear Decommissioning Cha a 0.43% 0.51 0.47 0.47 0.47 0.47 0.47 0.47 0.47 0.47 0.47 0.47 0.47 0.47 36 Medium Llght and Power 37 Total Average Customer Charge 94.66 94.66 94.66 94.66 79.55 76.31 77.31 78.52 79.05 79.40 79.86 80,02 80.39 38 PX Price 22.52 23.39 22.06 23.74 25.55 26.45 27.38 28.35 28,77 29.20 29.63 30.07 30.52 39 Ancillary Service & ISO/PX Charges 1.48 1.49 1.47 1.50 1.53 1.55 1.57 1.58 1.59 1.60 1.61 1.62 1.62 40 Line Loss Charge 2.16 2.24 2.12 2.27 2.44 2.52 2.61 2.69 2.73 2.77 2.81 2.85 2.89 41 Delivered Energy Price 26.16 27.12 25.65 27.51 29.52 30,52 31.55 32.62 33.09 33.57 34.05 34.54 35.04 42 Employee Transition CTC 0.00 0.00 0.00 0.00 0.00 0.00 0.00 01X) 0.00 43 Long Term Purchase Contracts (QF's) 13.25 11.18 7.06 6.69 5.76 5.57 5.37 5.35 5.24 4.94 4.74 4.24 3.93 44 Transition CTC 23.56 17.99 23.74 22.38 45 CTC's 36.81 29.17 30.81 29.06 5.76 5.57 5.37 5.35 5.24 4.94 4.74 4.24 3.93 46 Transmission Charge 4.34% 5.10 5.19 5.19 5.19 5.47 554 5.58 5.63 5.67 5.72 5.76 5.81 5.66 47 Distribution Charge 20.87% 24.93 31.64 31.51 3140 32.97 33.25 33.39 33.53 33.67 33.82 33.97 34.12 34.27 48 Public Purpose Programs Charge 1.05 1.03 0.99 0.97 0.95 0.93 0.91 0.89 0.87 0.85 0.83 0.81 0.79 Pludear Decommissionini Char 0.43% 0.51 0.51 0.51 0.51 0.51 0.51 0.51 0.51 0.51 0.51 0.51 0.51 0.51 51 Large Light and Power 52 Total Average Customer Charge 63.09 63.09 63.09 63.09 68.78 71.27 72.30 73.58 74.08 74.38 74.80 74.88 75.20 53 PX Price 22.19 23.03 24.85 26.74 28.78 29.79 30.84 31.93 32.41 32.89 33.38 33.86 34.38 54 Andillary Service & ISO/PX Charges 1.47 1.49 1.52 1 56 1.59 161 1.63 1.65 1.66 1.67 1.67 1.68 1.69 Prepared by: Hunwood Energy Services, Inc P. 1 of 3 03/20119999.37 AM NCPA Study Unbundled Rates by Class Model5Lxls -AjBj C D 1 E I F 1 S 1 AF I AS I 8F I 8S CF CS DF DS EF I ES FF FS 1 '97 Rate 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 E/Mwh) Allocator Average Average Avera2e Average Average Avera2e Avera2e Average Average Averaq a Average Average Average 55 Line Loss Charge 2.13 2.21 2.37 2.55 2.73 2.83 2.92 3.02 3.07 3.11 3.15 3.20 3.25 56 Delivered Energy Price 25.80 26.73 28.74 30.84 33.10 34.23 35.39 36.60 37.13 37.67 38.21 38.76 39.32 57 Employee Transition CTC 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 58 Long Term Purchase Contracts (QF's) 13.08 11.00 8.01 7.58 6,53 6.31 609 6.06 5.93 5.60 5.37 4.80 4.45 59 Transition CTC 1.51 (4.04) (2.92) (4.48) 60 CTC's 14.58 6.96 5.08 3.10 6.53 8.31 6.09 6.06 5.93 5.60 5.37 4.80 4.45 81 Transmission Charge 4.41% 5.27 5.27 5.27 5.27 5.55 5.62 5.67 5.71 5.76 5.80 5.85 5.90 5.95 62 Distribution Charge 13.55% 16.19 22.89 22.76 22.65 23.75 23,92 23.98 24.04 24.11 24.18 24.25 24.32 24.39 63 Public Purpose Programs Charge 0.74 0.73 0.72 0.71 0.70 0.68 0.67 0.65 0.64 0.62 0.61 0.60 0.58 -Nuclear Decommissionin Charge 0.43% 0.51 0.51 0.51 0.51 0.51 0.51 0.51 0.51 0.51 0.51 0.51 0.51 0.51 66 Street Lighting 67 Total Average Customer Charge 122.45 122.45 122.45 122.45 87.98 77.46 78.42 79.59 80.08 80.40 80.83 80.96 81.29 66 PX Price 19.93 20,49 21.66 23.30 25,08 25.96 26.86 27.83 28,24 28.66 29.09 29.52 29.96 G9 Ancillary Service & ISO/PX Charges 1.43 1.44 1.46 1.49 1.53 1.54 1.56 1.57 1.58 1.59 1.60 1.61 1.61 70 Line Loss Charge 1.92 1.97 2.08 2.23 2.39 2.48 2.56 2.65 2.68 2.72 2.76 2.80 2.84 71 Delivered Energy Price 23.26 23.91 2520 27.03 29.00 29.98 31.00 32.05 32.51 32.98 33.45 33.93 34.42 72 Employee Transition CTC 0.00 0.00 0.00 0.00 0,00 0.00 0.00 0.00 0.00 73 Long Term Purchase Contracts (CF's) 12.15 10.03 7.12 6.75 5.81 5.62 542 5.39 5.28 4.98 4.78 4.27 3.96 74 Transition CTC 53.58 48.41 50.24 48.95 75 CTC's 65.72 58.44 57.36 55.70 5.81 562 5.42 5.39 5.28 4.98 4.78 4.27 3.96 76 Transmission Charge 1.18% 1.41 1.41 1.41 1.41 1.49 1.50 1.52 1.53 1.54 1.55 1.57 1.58 1.59 77 Distribution Charge 24.61% 29.40 36.10 35.98 35.86 37.68 38.02 38.19 36.37 38.55 38.74 38.92 39.11 39.31 78 Public Purpose Programs Charge 2.13 2.08 1.99 1.94 1.88 1.83 1.78 1.74 1.69 1.64 1.60 1.55 1.51 Nuclear Decommissioning. Char a 0.43% 0.51 0.51 0.51 0.51 0.51 0.51 0.51 0.51 0.51 0.51 0.51 0.51 0.51 81 Agricultural 82 Total Average Customer Charge 108.80 108.80 108.80 108.80 96.35 92.82 94.04 95.48 96.18 96.71 97.34 97.68 98.22 83 PX Price 21.61 22.51 24.08 25.91 27.89 28.87 29.89 30.94 31.41 31.87 32.35 32.83 33.32 84 Ancillary Service & ISO/PX Charges 1.48 1.48 1.51 1.54 1.58 1.59 1.61 1.63 1.64 1.65 1.66 1.66 1.67 85 Line Loss Charge 2.08 2.16 2.30 2.47 2.65 2.74 2.84 2.93 2.97 3.02 3.06 3.10 3.15 86 Delivered Energy Price 25.15 28.15 27.89 29.92 32.11 33.20 34.34 35.51 36.02 36.54 37.06 37,60 38.14 87 Employee Transition CTC 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 88 Long Term Purchase Contracts (QF's) 10.87 9.08 7.05 6.69 5.76 5.57 5.37 5.34 5.23 4.94 4.74 4.23 3.92 89 Transition CTC 28.27 21.75 22.75 21.20 90 CTC's 39.13 31.43 2981 27.88 5.76 557 5.37 5.34 5.23 4.94 4.74 4.23 3.92 91 Transmission Charge 5.28% 6.30 6.30 6.30 6.30 6.65 6.73 6.78 6.84 6.89 6.95 7.00 7.06 7.11 92 Distribution Charge........ 30.55% 36.49 43.20 43.07 42.96 45.16 45.59 45.83 46.07 46.31 46.56 46.81 47.06 47.31 93 Public Purpose Programs Charge 1.22 1.23 1.23 1.23 1.23 1.23 1.23 1.23 1.23 1.23 1.23 1.23 1.23 Nuclear Decornmissionin2 Char a 0.43% 0.51 0.51 0.51 0.51 0.51 0.51 0.51 0.51 0.51 0.51 0.51 0.51 0.51 96 OTHER RETAIL 97 Total Average Customer Charge 106.39 106.39 106.39 106.39 89.46 84.54 85.67 87.04 87.64 86.05 88.58 88.78 89.20 98 PX Price 21.89 22.80 24.42 26.28 28.28 29.28 30.31 31.38 31.85 32.33 32.81 33.30 33.79 99 Ancillary Service & ISO/PX Charges 1.47 1.48 1.51 1.55 1.58 1.60 1.62 1.64 1.65 1.66 1.66 1.67 1.68 100 Line Loss Charge 2.10 2.19 2.33 2.50 2.69 2.78 2.87 2.97 3.01 3.06 3.10 3.15 3.19 101 Delivered Energy Price 25.47 26.47 28.27 30.33 32.55 33.66 34.81 36.00 36.51 37.04 37.58 38.12 38.67 102 Employee Transition CTC 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Prepared by: Henwood Energy Services, Inc. P. 2 of 3 03129/19999:37 AM NCPA Study Unbundlud Rates by Class Model5f.xls JAIBI C 1 D 1 E I F I S I AF I AS I BF I BS I CF I CS I DF I DS I EF I ES I FF I FS 1 '97 Rate 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 S/MWh) Allocalor Average Avera a Average Average Average Avera2e Average Avera2e Average Average Average Average Average 103 Long Term Purchase Contracts (QF's) 12.94 10.89 7.84 7.43 6.40 6.18 5.96 5.94 5.81 5.49 5.27 4.71 4.36 104 Transition CTC 32.29 26.50 27.90 26.37 105 CTC's 45.24 37.39 35.74 33.80 6.40 6.18 5.96 5.94 5.81 5.49 5.27 4.71 4.36 106 Transmission Charge 3.65% 4.36 4.36 4.36 4.36 4.60 4.66 4.69 4.73 4.77 4.81 4.85 4.88 4.92 107 Distribution Charge-.. 24.97% 29.84 36.54 36.41 36.30 38.14 38.49 38,68 38.85 39.03 39.22 39.41 39.60 39.80 108 Public Purpose Programs Charge 0.98 1.11 1.10 1.08 1.07 1.05 1.03 1.02 1.00 0.99 0.97 0.96 0.95 109 Nuclear Decommissioning Charge 0.43% 0.51 0.51 0.51 0.51 0.5t 0.51 0.51 0.51 0.51 0.51 0.51 0.51 0.51 110 Prepared by: Henwood Energy Services. Inc P. 3 of 3 03/29/19999:37 AM 1998 Rate Class Allocators - I998 Sales IMWh Trans Dist PPP GePICTC Nuke Det Total NOTES: RESIDENTIAL E-1 20.817,882 3.321 29.061 3.443 63.750 0.425 ELA 1,648,514 4.000 15.880 3.736 75.977 0.425 E-7 1.841,918 3.452 28.298 3.550 84.275 0.425 E-8 573,366 3.917 25.523 3.525 86.610 0.425 assumed to include EL -8 S SUBTOTAL Imwn weighted] 24.881.680 3.369 28.048 3.472 84665 0.425 100.000 AGRICULTURAL ignore P and T AGA A 179.031 3.863 40.977 3.345 61.389 0.425 AG -RA 30.913 3.390 37.913 1435 54.837 0.425 AG -VA 38,805 3.072 36.722 3.440 55.741 0.425 AG -4A 132.592 3.641 37.366 3.449 55.119 0.425 AG -SA 85,432 5.198 32.259 3.524 58.594 0.425 AG18 288.379 3.905 34.053 3.408 58.209 0.425 AG -RB 30.444 3.659 29.580 3.452 62.884 0.425 AGVB 23,608 3.550 30.253 3.467 61.975 0.@5 AG -48 5 374,321 4.301 29.126' 3.487 62.661 0.425 use S AG -4C 41.155 1.203 38185 3.455 50.632 0.425 AG -58 2,289.539 5.926 28.784 3.624 61.241 0.425 use S AG -5C 35.679 8.205 29.099 3.640 59.831 0.425 SUBTOTAL (Mwh weighted) 3,547,898 5.276 30.549 3.561 60.192 0.425 100.000 STREETLIGHTS 318.424 1,180 24.607 5.442 68,144 0.425 100.000 SMALL L&P A-1 4,549,490 3.321 29.061 3.443 63.750 0.425 A-6 1,918,456 2.779 17.936 3.560 75.298 0.425 A-15 1,578 2.298 88.287 3.292 27.700 0.425 TC -1 144.061 5.961 36.278 3.144 54.192 0.425 SUBTOTAL Imwh weighted] 6.813.585 3.221 26.001 3.470 68.aa3 0.425 100.000 MEDIUM L&P New makes A-10 8 E-19 A-10 10.811.597 4.048 21.508 3.558 70.461 0.425 100.000 Assume as at Secondary (S) level E-19 E-19 T 5.353 3.176 - 22.750 3.854 69.987 0.425 Assume average of Fi m & Nonfirm figures. E-19 P 608.929 2-650 14,210 3.685 78.622 0.425 E-19 S 9,023.918 4.774 20.598 3.594 70.811 0.425 A -RTP -195 49.964 2.058 17.760 3.659 78.098 0.425 SUBTOTAL - E-19 10,488,192 SUBTOTAL (mwh weighted) 21.299.789 4.344 20.670 3.576 70.792 0.425 100 000 URGE L&P E-20 T 6.599.658 3.337 55" 4.047 88.647 0.425 Assume avenge o7 Firm & Non6rm figures E-20 P 6,138.681 1.785 15.036 3.756 76-996 0.425 E-205 4,390,767 7.210 24.010 3.645 64.710 0.425 A -RTP -20 T 18,000 1.805 2.517 3.593 91.880 0.425 A.RTP-20 S 409,772 1.873 15.407 3.648 78.647 0.425 SUBTOTAL -TARIFFS 17,550,878 4.426 13.798 3.834 77.605 0.425 100.000 CONTRACTS: T 348.021 3.201 4.317 3.144 88.913 0.425 CONTRACTS:P CONTRACTS: S - 21,165 10.005 32.490 3.144 53,928 0.425 SUBTOTAL -CONTRACTS 360,188 3.591 5.933 3.144 46.907 0.425 SUBTOTAL Imwh -ightedl 17.926.064 4.400 13.546 3.821 77.796 0,425 100.000 STANDBY T 128,722 12.174 23.593 3.687 60.121 0.425 P 10.512 6.645 51.172 3.313 38.445 0.425 S 1,468 8.491 30.361 3.470 53.247 0.425 SUBTOTAL (mwh welghted] 142,702 11.629 25.935 3.654 56.357 0.425 100 000 TOTAL 74,730.142 3.987 22.443 3.600 69.545 0.425 100.000 OTHER RETAIL 3.651 24.973 3.507 67.443 0.425 100.000 (Other Retail is average of Residential, Small L&P, and Medium LSPI A9odators come hem PG&E AW. Rate Group Cost OCIioaton Mem trandoum Account (Effective VtM9 To do: as needed, update sales weights /90BPG E Wet 52.99110 71.073.8 1.16 1,175,569.9? _ -4,49604 w. _ _.�_-E __. _ __. __.. 1996 Sanfran 1,826.95 45,436.50. 65,973.07. -20,538,57 1998 PG E South: 5,442.12:' 124215.78 54.989.94 69.225.82 Total 1998 60.262.17 1999 PG E Main 51.892.41 1.210.329.67 1.208198.42 2.031,25 PG_E 1999 SanFmn 1,575,87 41,338.92 63,959.16( -22.620.24 i 1999 PG E South 5.357.05 128.863.32 56.771.92 72.09140 81 1....�.._ 29_._ 2000PG EMain 54,079.241,389,145.251159,a7B..008.64 PG -E 2000 SanFran 2,114.72. 63.225.85 79,205.78! .15,979.94 2000 PG_E South: 5,856.67 151,525.22 84.124.80; 87,400.42 Based on forecast normalized data. Residential E1SB $4,773 E1SB (EA) $14,148 $14,574 ED $166 $167 EM $294 $280 A10 G3P) $14,608 $15,021 E1SB (EA) 127,968 131,819 ED 1,823 1,833 EM 2,536 2,412 A10(G2) 132,327 136,064 36.53% Average $110.39 $110.40 Small Light & Power Al (G1) $4,951 $4,773 A10 (G2) $9,925 $10,070 A10(G3S) $560 $695 A10 G3P) $99 $123 $15,535 $15,661 Al (G1) 41,069 39,592 A10(G2) 99,308 100,760 A10 (G3S) 6,288 7,799 A10 G3P) 1,009 1,252 147,674 149,403 40.11% Average $105.20 $104.82 E19S (G4S) $1,635 $2,178 E19P(G4P) $750 $761 $2,385 S2,939 E19S (G4S) 18,338 24,430 E19P (G4P) 9,641 9,786 27,979 34,216 9.19% Average $85.24 $85.90 E20S (G5S) $1,052 51,678 E20P(G5P) $436 $443 E20P (11 P) $1,264 $1,283 $2,752 $3,404 E20S (G5S) 10,367 16,535 E20P (G5P) 6,616 6,715 E20P (11 P) 20,423 20,730 37,406 43,980 11.80% Avetage $73.57 $77.40 ES 8,777 8,810 2.37% 354,163 372,472 100.00% REGIONALIZED RATE CALCULATION - Line 35 PG&E 19.98 2QU 21241 24112 2803 2049 21205 2425 290Z 29.4.11 2049 2414 2411 2412 2413 2414 2415 Residential $107.53 $107.53 $107.53 $98,40 $99.01 $99.48 $100.18 $100.14 $100.07 $92.82 $93.04 $93.49 $93.96 $94.43 $94.91 $95.39 $95,88 Small Light & Power $112.85 $112.85 $112.85 $96.87 $97.44 $97.88 $98.55 $98.47 $98.37 $90.75 $90.95 $91.38 $91.83 $92.29 $92.75 $93.21 $93.67 Medium Light & Power $94.66 $94.66 $94.66 $75.18 $76.31 $77.31 $78.53 $79.05 $79.41 $79.86 $80.02 $80.39 $80.81 $81.24 $81.68 $82.12 $82.57 Agricultural $108.81 $`108.81 $108.81 $91.42 $92.83 $94.05 $95.49 $96.19 $96.72 $97.35 $97.69 $98.23 $98.77 $99.31 $99.85 $100.40 $100.95 Streetlighting $122.45 $122.45 $122.44 $76.37 $77.46 $78.42 $79.58 $80.08 $80.40 $80.83 $80.96 $81.29 $81.65 $82.01 $82.37 $82.73 $83.09 Large Light & Power $63.09 $63.09 $63.09 $70.14 $71.27 $72.30 $73.57 $74.08 $74.38 $74.80 $74.88 $75.20 $75.59 $76.00 $76.41 $76.83 $77.25 Other Retail $106.39 11063 $.106,39 $83.27 $84,5.4 $8567 $87.04 $87.64 10.45 $88.58 $88.78 $8920 $89.65 $9410 $94.5$ $91.02 $91.48 System $94.64 $94.64 $94.66 $84.84 $65.71 $86.46 $87.43 $87.67 $87.80 $84.85 $85.00 $85.36 $85.77 $86.18 $86.61 $87.03 $87.46 Residential 1.0000002 0.9999999 0.91512 1.00617 1.00479 1.00706 0.99962 0.9993 0.92757 1.00236 1.00481 1.00502 1.005 1.00508 1.00506 1.00514 Small Light & Power 1.0000007 1.0000006 0.85844 1.0058 1.00456 1.00689 0.99918 0.9989 0.92258 1.0022 1.00475 1.00492 1.00501 1.00498 1.00496 1.00494 Medium Light & Power 1.0000008 1.0000007 0.79427 1.01507 1.0131 1.01566 1.0067 1.00448 1.00574 1.00204 1.00456 1.00524 1.00532 1.00542 1.00539 1.00548 Agricultural 1.0000187 1.0000159 0.84015 1.01544 1.01318 1.0153 1.00732 1.00549 1.00652 1.00349 1.00555 1.00547 1.00547 1.00544 1.00551 1.00548 Streetlighling 0.9999968 0.9999971 0.62369 1.0143 1.01234 1.0149 1.00622 1.00403 1.00529 1.00162 1.00414 1.00439 1.00441 1.00439 1.00437 1.00435 Larne Light & Power 1.0000004 1,0000005 1.11178 1.01606 1.01453 1.01762 1.0068 1.00412 1.00563 1.00115 1.00419 1.00521 1.00542 1.00539 1.0055 1.00547 Other Retail 1 1 0.782613 1.01534 1.01335 1.01591 1.00694 1.00472 1.00597 1.00226 1.00478 1.005 1.00502 1.00511 1.00509 1.00516 System 1.0000738 1.0002158 0.89622 1.01027 1.00872 1.01126 1.00276 1.00143 0.96643 1.00172 1.0043 1.00479 1.00484 1.00489 1.0049 1.00494 Residential $110.40 $110.40 $110.40 $101,03 $101.65 $102.14 $102.86 $102.82 $102.75 $95.31 $95.53 $95.99 $96.47 $96.95 $97.45 $97.94 $98.44 Small Light & Power $104.82 $104.82 $104.82 $89.98 $90.50 $90.92 $91.54 $91.47 $91.37 $84.29 $84.48 $84.88 $85.30 $85.72 $86.15 $86.58 $87.01 Medium Light & Power $85.90 $85.90 $85.90 $68.23 $69.26 $70.16 $71.26 $71.74 $72.06 $72.47 $72.62 $72.95 $73.34 $73.73 $74.12 $74.52 $74.93 Agricultural $108.81 $108.81 $108.81 $91.42 $92.83 $94.05 $95.49 $96.19 $96.72 $97.35 $97.69 $98.23 $98.77 $99.31 $99.85 $100.40 $100.95 Streettighting ,$122.45 $122.45 $122.45 $76.37 $77.46 $78.42 $79.59 $60.08 $80.40 $60.83 $80.96 $81.30 $81.65 $82.01 $82.37 $82.73 $83.09 Large Light & Power $77.40 $77.40 $77.40 $86.05 $87.43 $88.70 $90.27 $90.88 $91.26 $91.77 $91.87 $92.26 $92.74 $93.24 $93.75 $94.26 $94.78 Other Retail $106.39 $106.39 $106.39 $83.27 $84.55 $85.67 $87.04 $87.64 $88.05 $88.58 $88.78 $89.20 $89.65 $90.10 $90.56 $91.02 $91.49 Residential 136,064 138,064 140.094 142,155 144,246 146,369 148,523 150,710 152,929 155,182 157,468 159,789 162,144 164,535 166,962 169,424 171,924 Small Light & Power 149,403 151,644 153,919 156,227 158,571 160,949 163,364 '165,814 168,301 170,826 173,388 175,989 178,629 181,308 184,028 186,788 189,590 Medium Light & Power 34,216 34,729 35,250 35,779 36,315 36,860 37,413 37,974 38,544 39,122 39,709 40,304 40,909 41,522 42,145 42,778 43,419 Agricultural 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Slreetlighting 8,810 8,898 8,987 9,077 9,168 9,260 9,352 9,446 9,540 9,636 9,732 9,829 9,928 10,027 10,127 10,228 10,331 Large Light & Power 43,980 44,640 45,309 45,989 46,679 47,379 48,090 48,811 49,543 50,286 51,041 51,806 52,583 53,372 54,173 54,985 55,810 Other Retail 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 System 372,472 377,975 383,559 389,227 394,979 400,817 406,741 412,755 418,858 425,051 431,338 437,718 444,193 450,765 457,435 464,204 471,014 Residential $15,021 $15,242 $15,466 $14,362 $14,663 $14,950 $15,277 $15,496 $15,713 $14,790 $15,043 $15,338 $15,642 $15,952 $16,270 $16,593 $16,925 Small Light & Power $15,660 $15,895 $16,134 $14,058 $14,351 $14,633 $14,955 $15,167 $15,377 $14,399 $14,647 $14,938 $15,236 $15,542 $15,854 $16,172 $16,495 Medium Light & Power $2,939 $2,983 $3,028 $2,441 $2,515 $2,586 $2,666 $2,724 $2,777 $2,835 $2,884 $2,940 $3,000 $3,061 $3,124 $3,188 $3,253 Agricultural $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Streetlighting $1,079 $1,090 $1,100 $693 $710 5726 $744 $756 $767 $779 $788 $799 $811 $822 $634 $846 $858 Large Light & Power $3,404 $3,455 $3,507 $3,957 $4,081 $4,203 $4,341 $4,436 $4,521 $4,615 $4,689 $4,780 $4,877 $4,977 $5,078 $5,183 $5,289 Other Retail $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 System $38,103 $38,665 $39,235 $35,511 $36,320 $37,098 $37,983 $38,579 $39,155 $37,418 $38,051 $38,795 $39,566 $40,354 $41,160 $41,982 $42,820 13$2 2004 244.1 2442 1041 21104 2405 2006 200-7 2801} 2489 2914 2411 2012 2411 2Q14 2414 PG&E system regionalized $102.30 $102.30 $102.29 $91.23 $91.95 $92.56 $93.38 $93.47 $93.48 $88.03 $88.22 $88.63 $89.07 $89.52 $89.98 $90.44 $90.90 PGE regionalized 9-98 E1 03/29/1999 12:07 PM Notes and Sources Started with Henwood study to get System rate and sales for PG&E and Lodi rate schedule usage models. 1) Used Lodi customer shape and average usage developed in the usage models, then applied PG&E's current effective rates to develop the regionalized rates above. For Agricultural and Other used PG&E class rate. 2) Used the usage model kWh to develop the percentages by class 3) Used the PG&E system sales for 1999 and applied the Lodi % to get PG&E regionalized sales then multiplied by the regionalized rate to get renenues, then divided total revenue by total sales to get the average regionalized system rate. 4) Applied the ratio change in PG&E system rate year to year developed in Henwood study and applied to the regionalized system rate of the prior year. Usage models: Residential - EA9809.xls, Small Light and Power- G19808.xls, G29808.xls, G3S9809.xls, G3P9809.xls Medium Light and Power - G4P9809.xls, G4S9809.xls, Streetlighting - ES9808.xls Large Light and Power - G5P9809.xls, G5S9809.xls, 11 P9808.xls. _... 1999 2444 7.441 2442 2441 2044 2445 206 2442 249.@ 200;?. 2014 24]1 2911 2411. 2014 2415 Residential 36.5% 36.5% 36.5% 36.5% 36.5% 36.5% 36.5% 36.5% 36.5% 36.5% 36.5% 36.5% 36.5% 36.5% 36.5% 36.5% 36.5% Small Light & Power 40.1% 40.1% 40.1% 40.1% 40.1% 40.2% 40.2% 40.2% 40.2% 40.2% 40.2% 40.2% 40.2% 40.2% 40.2% 40.2% 40.2% Medium Light & Power 9.2% 9.2% 9.2% 9.2% 9.2% 9.2% 9.2% 9.2% 9.2% 91% 9.2% 9.2% 9.2% 9.2% 9.2% 9.2% 9.2% Agricultural 0.0% 0.0%u 0.0% 0.0% 0.0% 0.0% 0.0%u 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0%u 0.0%, 0.0%a Streetlighting 2.4% 2.4% 2.3% 2.3°! 2.3% 2.3% 2.3% 2.3% 2.3% 2.3%, 2.3% 2.2% 2.2% 2.2% 2.2% 2.2% 2.2% Large Light & Power 11.8% 11.8% 11.8% 11.8% 11.8% 11.8% 11.8% 11.8% 11.8% 11.8% 11.6% 11.8% 11.8% 11.8% 11.8% 11.8% 11.8% Other Retail aim Um UN QMA as% H% in Q Q% U -M 0-"0 4.4°!a QAM 4.4°!a 4,4°!n Q&A O.QlQ 0.0% System 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0%u 100.0% 100.0% 100.0% 100.0% 100.0% 100.0%u 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0%u 100.0% 100.0%u 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% PGE regionalized 9-98 E1 03/29/1999 12:07 PM BASE CASE - COST STRUCTURE OPERATING RESULTS "Sr- CASE JOe 03/29/1999 8.31 1999 2444 201 2402 2443 2Q49 2445 24417 2QQZ 2446 2448 2414 20.11 2412 2413 2814 2415 1 Maximum Competitive Revenues $36,469 537,008 $37.554 538,109 536,683 $37,469 $38,363 $38.965 $39,155 $37,418 $38,051 $38,795 $39,566 $40,354 $41,160 $41,9a2 $42,820 2 Non -Operating Income Salo $834 5859 $885 $911 $939 $967 $996 $1,026 $1,056 $1.088 $1,121 $1,154 $1.189 $1,225 $1,261 $1,299 3 Interest Income $1,011 $709 $499 $330 $326 $281 $215 $153 $139 $125 $0 $0 $0 $0 $52 $61 $80 4 Other Revenues iQ SQ SQ 10 SQ S4 5Q so 50 S4 s4 SQ 54 54 s4 IQ lia 5 TOTAL REVENUES $36,289 $38,551 $38,912 $39,324 $37,920 $38,689 $39,545 $40,114 $40,320 $38,599 $39,139 $39,916 $40,720 $41,543 $42,437 $43,304 $",199 6 Generation Debt Service $14,252 $74,640 513,763 311,461 $10,210 $10,876 $13.029 $10,111 $9,682 $9,912 $9,777 $9,534 $6,374 $6,231 $6,261 $6,249 $6,271 1 Transmission Debt Service $928 $926 $924 $832 $962 $894 5891 5889 $887 $884 $882 5879 5668 $644 $642 $639 $637 8 Lodi Facilities Debt Service so $0 SO SO $0 $0 $0 $0 so so so $0 so so so 50 $0 9 Distribution Capital Debt Service so SQ 19 EQ 14 SQ SQ SQ 10 SQ 114 SQ s4 S4 s4 SQ S4 10 TOTAL DEBT SERVICE $15,181 $15,566 514,687 $12,293 $11,173 $11,770 $11,920 $11,000 $10,569 $10,796 $10,659 510,413 $7,041 $6,875 $6,903 56,898 $6,908 11 Lodi Generation O&M $9,237 $9,514 $9,799 510,093 $10,396 $10.708 $11,029 $11,360 $11,701 512,110 $12,296 572,483 $12,678 $12,876 $13,078 $13,282 $13,491 12 Markel Generation 19962 514.291 311.685 S12137 313.365 514 025 519.2113 .515152 11 S SOn S16.45Z 516 534 117.017 117-359 $17,709 516 466 118.4 310.1341 13 GENERATION EXPENSES $9,237 $9,514 $9,799 $10,093 510,396 $10,708 $11,029 $11,360 $11,701 $12,110 $12,296 $12,483 $12,678 $12,876 $13,078 $13,282 $13,491 14 TRANSMISSION 08M $2,768 $2.787 $2.807 $2,826 S2,84T $2,867 $2,887 $2,909 $2,929 $2,951 $2,972 $2,054 $2,126 52,200 $2.278 $2.358 $2.441 15 Distribution O&M $6,484 $6,646 $6.012 $6,982 $7,155 $7,334 $7,517 $7,704 $7,896 $8,093, $8,295 $8,502 Sa,714 $8.931 $9,154 $9,3412 $9,616 16 Dislnbution Capital 52.544 52544 S250Q 1244Q 52.454 52101 52.153 52.201 122E1 12.316 52376 52433 52.996 52.55@ $2.622 12687 52754 17 TOTAL DISTRIBUTION EXPENSES $8,984 $9.145 $9.312 $8,982 59,205 $9,435 $9,670 $9,911 $10,157 $10,411 $10,671 $10,937 $11,210 $11,489 $11,776 $12,069 $12,370 16 PUBLIC BENEFITS EXPENSES $1,031 111055 $1,043 $975 $958 5991 51,012 $1,003 57,098 $1.034 $1,043 $1,023 $942 $953 $970 $888 $1,003 19 TOTAL EXPENSES $37,200 $38,068 $37,648 $35,169 $34,578 $35,171 $36,519 $36,182 $36,364 $37,302 $37,641 $36,910 $33,997 $34,394 $35.005 $35,584 $36,213 1438 2444 2441 2942 2443 2441 2445 2446 2447 2446 200 2414 2Q11 2412 2413 2419 2415 20 BEGINNING FUND BALANCE $22,519 $19,314 $15,516 $12,519 $12,776 $12,230 $11,293 $10,477 $10,596 $10,741 $8,259 $6,003 $5,280 $5,260 $5,608 $5,986 $6.397 21 Working Reserves $5,580 $5,710 $5,647 55,275 $5,187 $5,366 $5,478 $5,427 55,455 $5,595 $5.646 $5.537 55,100 55,159 $5,251 $5,338 $5.432 22 Lodi Facilities Reserve 995 51.047 114$6 51196 51.242 S1259 11.116 51.364 S144 S151 5.1584 &165 11,737 Slat 515414 51.895 S2Q68 23 ENCUMBERED RESERVES $5,580 $5,710 $5,647 55,275 55,187 55,366 $5,478 $5,427 55,455 $5,595 $5,646 $6.537 $5,100 $5,159 $5,251 $5,338 $5,432 24 DISCRETIONARY RESERVES $16,939 $13,604 $9.871 $7,243 $7,589 $6,872 $5,815 $5,050 $5,131 $5,146 $2,613 $466 $180 $101 $357 $648 $965 25 Interest Income $275 5291 $306 $323 5340 $357 $378 $398 5419 5441 $466 $491 $518 $546 $574 $605 $638 26 Net Revenues 11.46$ 5963 11264 591,55 53.342 52919 11026 53.931 13356 51.297 $1.436 13.446 56723 37.149 17.432 57.720 $7.9Bfi 27 TOTAL INCOME $1,364 $774 $1,570 $4,478 $3,682 $3275 $3,404 54,329 54,375 $1.738 $1964 $3,497 57,241 $7,895 $8.006 $8,325 $8,624 28 Lodi Facilities Expenditures so $0 s0 SO $0 $0 $0 Sa SO $0 s0 so $0 $0 $0 SO so 29 General Fund Capital Loan $350 $350 $350 $0 SO $0 $0 50 SO $0 50 $0 s0 s0 s0 $0 SO 30 General Fund Transfer 59.224 S9.220 141224 59124 59.224 19.224 54.22Q 54.224 34.224 59.224 5.4.224 542A YAM 59.224 922 59.224 54228 31 TOTAL EXPENDITURES $4.570 $4,570 $4,570 $4,220 54,220 $4,220 $4,220 $4,220 $4,220 $4,220 $4,220 $4.220 $4,220 $4,220 $4.220 $4.220 $4.220 Ila Surplus Collection Rebate -53,041 -53,128 .$3,406 -$3,695 43,983 32 ENDING FUND BALANCE 519,314 $15,510 $12,518 $12,776 $12,238 $11,293 $10,477 $10,566 510,141 $8,259 $6,003 $5,280 $8,301 $0,735 $9.394 $10,092 $10,900 43.041 47.129 -13,408 43.695 *$31863 46,85 -$6.94 - -$7.45 -$7.96 48.41 1488 2444 2041 2442 244,7 2449 2045 20451 2447 2094 2048 2014 2411 2412 2913 2414 2414 33 MWIISates 372,472 377,975 383,559 389,227 394,979 400,817 406,141 412,755 418,858 425,051 431,338 437,718 444,193 450,765 457,435 464,204 471,074 34 Mkt Power - $lmwh $26.75 $28.42 $30.49 $32.72 $33.84 $34.99 $36.19 $36.71 $37.24 $37.78 $38.32 $38.88 $39.08 $39.29 $39.49 $39.70 - $39,91 35 Adjusted Regional Bundled - Slmwh $102.30 3102.30 $102.29 $91.23 $91.95 $92.56 $93.38 $93.47 $93.48 $88,03 $88.22 $88.63 $89.01 $89.52 $89.98 $90.44 $90.90 36 Competitive Rate Surcharge(/Rebale) ($4.39) ($4.39) ($4.38) $6.68 50.92 $0.93 $0.93 $093 $0.00 $0.00 $0.00 $0.00 ($6.85) ($6.94) ($7,45) ($7.96) ($8.41) 37 System Average Rate - Vnrwh $97.91 $97.91 $97.91 $97.91 592.87 $93.46 $94.32 594.40 $03.48 $88.03 $11822 $88.63 $8723 $82.58 $82.53 $82.48 $8249 BASE CASE 1999 2009 2091 2442 20.01 2444 2094 2498 2442 2448 202 2414 1011 21W 2413 2414 2015 DISTRIBUTION/NON-BYPASSABLE $34.27 $36.00 $38.91 $36.42 $36.42 $36.54 $36.64 $36.66 $36.73 $36.85 $36.94 $36.96 $36.86 $36.96 $37.09 $37.21 $37.35 TRANSMISSION $9.92 $9.92 $9.72 $9.40 $9.64 $9.38 $9.29 $9.20 $9.11 $9.02 $8.94 $6.70 $6.29 $6.31 $6.38 $6.46 $6.53 GENERATION $53.72 $53.09 $30.49 $32.72 $33.84 $34.99 $36.19 $36.71 $37.24 $37.78 $38.32 $38.88 $39.08 $39.29 $39.06 $38.81 $38.60 CTC $9 44 54.44 11878 $19.36 $12.98 112.57 $12,21 511.83 SID 90 LLL "M 18 49 54.04 am 14 44 14.44 "M LODI SYSTEM AVG. RATE $97.91 $97.91 $97.91 $97.91 $92.87 $93.48 $94.32 $94.40 $93.48 $68.03 $88.22 $88.63 $82.23 $82.58 $82.53 $82.48 $82.49 COMPETITIVE RATE $102.30 $102.30 $102.29 $91.23 $91.95 $92.56 $93.36 $93.47 $93.48 $88.03 $88.22 $88.63 $89.07 $89.52 $89.98 $90.44 $90.90 MWH Sales 372,472 377,975 383,559 389,227 394,979 400.817 406,741 412,755 418,658 425,051 431,338 437,718 444,193 450,765 457,435 464,204 471,074 DISTRIBUTIOWNON-BYPASSABLE 1898 2044 2441 2442 2441 2044 2448 2M 2047 2448 2449 2414 2911 2012 2013 211A 2= Non -Operating Income -$810 -$834 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 30 $0 $0 Interest Income 41,011 -$709 $0 $0 $0 $0 $0 $0 $0 $0 $0 . $0 $0 $0 $0 s0 $0 Distribution Capital Debt Service $0 $0 s0 $0 $0 $0 $0 $0 $0 $0 $0 $0 s0 $0 30 $0 $0 Distribution O&M $6.4114 $6,646 $6,812 $6,982 $7,155 $7,334 $7,511 $7,704 $7,896 $8,093 $8,295 $8,502 $8,714 $8,931 $9,154 $9,382 $9,616 Distribution Capital $2,500 $2,500 $2,500 $2,000 $2050 $2,101 $2.153 $2,207 $2,261 $2,318 $2.376 $2,435 $2,496 $2,558 $2,622 $2,687 $2,754 PUBLIC BENEFITS EXPENSES $1,031 $1,055 $1,043 $975 $958 $991 $1,012 $1,003 $1,008 $1,034 $1,043 $1,023 $942 $953 $970 $986 $1,003 General Fund Capital Loan $350 $350 $350 $0 $0 $0 $0 $0 $0 $0 $0 $0 s0 $0 $0 $0 $0 General Fund Transfer -' S4220 14 224 59 220 14.224 S4220 14 220 54 224 S4220 54.224 &4220 54,224 59.224 S422 S422 S422 54 220 3,122 $12,764 $13,226 $14,925 $14,177 $14,383 $14,646 $14,902 $15,t34 $15,385 $15,665 $15,934 316,180 $16,372 $16,662 $16,966 $17,275 $17,593 TRANSMISSION im 2440 2441 2442 2041 2004 2445 2449 2441 2449 2449 2414 2411 24]2 2413 2414 2415 Transmis31on OebtService $928 $926 $924 $832 $962 $894 $891 $689 $867 $884 $882 $879 $668 $644 $642 $639 $637 Lodi Facilities Debt Service $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 s0 $0 $0 $0 TRANSMISSION O&M 52 766 S2787 32847 52 826 S2847 32447 52 887 S2908 52 929 $2951 52 972 $2054 32.124 &22 12 278 52 358 32341 $3,696 $3.713 $3,730 $3,658 $3,809 $3,760 $3,778 $3,798 $3,616 $3,835 $3,854 $2,933 $2,793 $2,844 $2,920 $2,997 $3,078 GENERATION 1992 2444 2441 2442 2443 240¢ 2445 244¢ 2002 2448 2449 2414 2411 2411 2013 2014 2415 Markel Generation $11,696 $12,737 $13,365 $14025 $14,718 $15,152 $15,598 $16,057 $16,530 $17,017 $17,359 $17,709 $18,066 $18,430 $18,801 Lodi Generation 523.489 $24,154 Generation $23,489 $24,154 $11,696 $12,737 $13,365 $14025 $14,718 $15,152 $15.598 $16,057 $16,530 $17,017 $17,359 $17,709 $18,0% $18,430 $18,801 2m 2003 2010 2411 2012 DISTRIBUTION/NON-BYPASSABLE BASE CASE QQSTS $19.04 1893 2=1 2001 2002 2403 200.4 200,4 2006 2042 Distribution O&M $17.41 $17.58 $17.76 $17.94 $18.11 $16.30 1118.46 $18.66 $18.85 Distribution Capital $6.71 $6.61 $6.52 $5.14 $5.19 $5.24 $5.29 $5.35 $5.40 Public Benefits Expenses $2.77 $2.79 $2.72 $2.50 $2.43 $2.47 $2.49 $2.43 $2.41 General Fund Capital Loan $0.94 $0.93 $0.91 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 General Fund Transfer $11.33 $11.16 $11.00 $1084 $10.68 $10.53 $10.38 $10.22 $10.08 CTC $0.00 $0.00 $18.78 $19.36 $12.98 $12.57 $12.21 $11.83 $10.40 Lodi Total $39.16 $39.08 $57.69 $55.79 $49.39 $49.11 $48.84 $48.49 $47.13 PG&E DisuibulionlNon-Bypassable $72.68 $71.01 $68.93 $54.69 $54.24 $53.64 $53.22 $52.74 $52.18 2m 2003 2010 2411 2012 20.L1 2014 2019 $19.04 $1923 $19.42 $19.62 $19.61 $20.01 $20.21 $20.41 $5.45 $5.51 $5.56 $5.62 $5.67 $5.73 $5.79 $5.85 $2.43 $2.42 $2.34 $2.12 $2.11 $2.12 $2.12 $2.13 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 40.00 $0.00 $9.93 $9.78 $9.64 $9.50 $9.36 $9.23 $9.09 $8.96 $4.38 $4.02 $6.09 $0.00 $0.02 $0.00 $0.00 $0.00 $41.23 $40.96 $43.05 $36.86 $36.99 $37.09 $37.21 $37.35 $46.00 $45.60 $45.43 $45.58 $45.73 $45.88 $46.03 $46.18 Other Contracts COTP/SOT Interconnection PG&E 03/29/1999 8:31 JIM $1.59 249.4 $1.59 201 $1.58 2442 $1.58 TRANSMISSION 29.02 $1.58 2004 $1.57 2406 EXPENSES 2446 - ALL 2442 CASES 2QM 2409 2MQ 2411 2012 2QU 20.]4 24.16 $2.57 $2.56 $2.55 $2.55 $2.54 $2.54 $1.57 $2.53 $1.57 $2.53 $1.56 $2.52 $1.56 $1.56 $1.55 $1.55 $1.54 $1.54 $1.54 $1.53 $3.27 $3.23 $3.18 $3.13 $3.09 $3.04 $3.00 $2.95 $2.91 $2.51 $2.87 $2.51 $2.83 $2.50 $2.79 $2.50 $2.49 $2.49 $2.48 $2.48 $4.15 $4.18 $4.16 $4.38 $4.44 $4.47 $4.51 $4.54 $4.58 $4.62 $4.66 $4.69 $2.74 $2.70 $2.67 $2.63 $2.59 $4.79 $4.88 $4.98 $5.08 $5.18 PROPOSED COST STRUCTURE AND OPERATING RESULTS We 1888 2944 2441 2092 2443 2049 2985 20Q4 2042 2Q4fl 2999 20.111 2011 2012 2411 2014 2411 " 1 Madmum Competitive Revenues $36.469 $37,008 $37,564 $37,990 $36.320 337,098 $37,983 $38,579 539,155 $37,418 $38,051 $38,795 $39,159 540,354 $41,160 $41,982 $42,820 2 NomOpwating Inane $810 6834 $859 $885 3911 $939 $967 $096 $1,026 $1.056 $1,088 $1,121 $1,154 $1,169 $1.225 $1,261 S1,299 3 Interest Income $1,011 $939 $792 $687 $696 $652 $588 5531 6522 $613 $369 5237 5177 5168 $130 $124 $126 4 Outer Revenues 30 !0 1Q 34 10 50 SE SQ 34 SO 112 39 IQ $4 114 30 34 s TOTAL REVENUES $38,289 $36,781 $39,205 $39,570 $37,927 $38,689 $39,538 $40,106 $40,703 $38,987 $39,508 $40,153 $40,490 $41,701 $42,521 $43,367 $44,245 6 Generation Debt Service $14,252 $14,640 113,783 Sft,461 $10,210 $10,876 $11,029 310,111 $9,682 $9,912 $9,777 59,534 $6,374 $6,231 $6,261 $6,249 56,271 7 Transmission Debt Service $928 $926 $924 $832 $962 $894 sag $689 $887 $884 5882 $879 $658 $044 3842 $639 $637 8 Lodi FarJ60es Debt SenAce 30 SO $O SO s0 s0 60 $0 s0 $0 SO SO $1,920 $1,950 $1,965 52,015 $2,045 9 Distribution Capital Debi Service 1892 "a Wfl 51355 5.1.345 51355 S135 IL= 51792 SLZ82 11792 1179 32.202 53150 S3 J5z $3.158 13 t58 18 TOTAL DEBT SERVICE $16,022 316,464 $13,003 313,616 512,528 $13,125 $13,275 312,35S $12,361 $12,589 $12,451 512,203 $11,243 $11.985 $12,045 $12,061 $12,111 11 Lodi Generation O&M $9,237 $9,514 $9799 $10,083 $10,306 $10,708 $11,020 511,360 $11,701 312,110 $12,298 512,483 $12,678 $12,878 573,078 513,282 813,491 12 $Vrket Generation 18 852 514 741 S116 312 737 11.3.355 114 425 119_7]8 515.152 11559 314.432 515 530 S t 7 0t7 $11.359 &17 7 114.464 519330 114 541 .t 13 GENERATION EXPENSES $9,237 69,514 $9,799 $10,093 St0,396 $10,703 $11,029 $11,360 311,701 612,110 $12,296 512,483 $12,678 $12,876 $13,076 $13,282 $13,491 ' 14 TRANSMISSION O&M 52,760 $2,787 $2,007 $2,626 $2,047 $2,667 $2,667 32,908 $2,929 $2,951 $2,972 $2,054 $2,126 $2,200 $2,270 112,350 52,441 15 Distribution 06M $6,484 116,646 $6,812 58,982 $7,155 $7,334 57.517 $7,704 $7,695 r 36,093 56,295 58,502 38,714 $8,931 $9,154 $9,382 59,616 10 Distribution Capital 5440 1514 3432 3854 SBZS 5584 AM Sao SZ40 S2fl3 1404 1431 1555 5401 3909 5835 3sni3 17 TOTAL DISTRIBUTION EXPENSES $7,084 $7,264 $1,449 $7,636 $7,630 $5,030 $0.233 $8,442 $8,656 $8,676 39,101 $9.333 $9,569 $9,012 $10,062 $10,317 $10,579 18 PU13UC BENEFITS EXPENSES $1.00i 31,027 $1,016 $973 $958 $990 61.010 $999 $1,016 $1,041 $1,049 $1,026 31,015 11,051 $1,068 $1,084 $1,101 t9 TOTAL EXPENSES $36,111 $37,076 $36,676 $35,180 $34,558 $35,719 $36,435 $36.065 $36.664 $37,567 $37.870 $37,103 $36,632 $37,925 $38,530 $39,102 $39,722 188E 2000 2001 2442 2493 2003 2905 2044 2002 2ffi4 2404 2414 2911 2012 2Q13 2014 2915 ' 20 BEGINNING FUND BALANCE $36.036 336,490 $24,706 $18,350 316,766 516,220 317.266 510,467 $10,621 $16,791 $14,362 $12.171 611,414 311,496 511,504 S11,759 $12,313 ' 21 Working Reserves $5,417 $5,561 $5,501 $5.271 $5,184 $5,356 $5.465 55,410 55,500 $5,835 $6,680 $5.565 55,495 $5,669 55,780 55,865 $5,958 22 Lodi Facilities Reserve 311112 &137 51572 s0 30 50 IQ 50 $2 S9 S0 30 14 SQ 5Q 34 SQ 23 ENCUMBERED RESERVES 518,529 $19,291 110,073 $5,277 $5,184 $5,358 $5.465 $5.410 $5,500 $5,635 $5,680 $5.565 $5,495 S5,689 $5,780 $5,865 $5,968 24 DISCRETIONARY RESERVES $19,507 $17,199 $14635 $13,073 $13,604 $12,662 $11.803 $11,057 $11,121 861,156 $6,682 S6,606 $5,919• $5,709 $5.724 $5894 16,361 25 Interest Income $045 $242 $469 5269 $283 $298 $318 $333 $351 $370 $391 $413 $436 $460 $484 $511 $540 26Nei Revenues - • - Sa 178 21.704 12 530 13 309 13368 1297 33103 SAAW SLM Si 420 31438 930 S38 S3-774 &3991 1g 265 14 523 27 TOTAL INCOME $3.024 $1,946 $2,999 $4.658 $3.652 $3,268 $3.419 $4,374 $4.390 31,790 $2.029 $3,463 $4,294 $4,236 $4,475 $4,776 55,063 . 28 Additional Stranded Cost Payment $0 30 SO SO 30 SO $0 SU SU s0 30 so 4407 $392 $318 5239 $161 29 Led FacilNes Expenditures SO $9,158 14,767 $0 $U $0 $0 $U $0 $0 $0 SO $0 $0 s0 s0 SO 10 General Fund Capital Loan $350 $350 $350 SO 30 $0 $0 SO $0 $0 $0 SO $0 $0 $0 $0 SO 31 General Fund Transfer.- 14 22D WA iIM it= am i3,2ZQ 51.220 L42A 19120 18.224 59.224 19.229 39.220 59.220 3!.220 UM 19.220 • 32 TOTAL EXPENDITURES $4,670 $13,728 $9,357 $4,220 54,220 $4,220 $4,220 $4,220 $4,220 $4,220 $4,220 $4,220 $3,813 $4,612 $4,538 $4,459 $4,381 33 ENDING FUND BALANCE $30.490 $24,708 118,350 110,788 $18,220 617,266 $16,467 516,621 $16,791 $14,362 $12,171 $11.414 $11,805 $11,112 111,441 $12,076 $12,997 1888 ZM 209.1 2042 2003 2001 2005 2094 2052 2445 2400 ZIM 2011 2412 2413 2419 2015 34 MINH Sales 372.472 3117,016 383,650 389,221 394.979 400,817 400.741 412,755 418.858 425,051 431,338 437,118 444,193 450,765 457,435 464,204 471,074 IS Mkt Power • 347hvh $26.75 $28.42 $30.49 $32.72 $33.84 534.99 135.19 536.71 $31.24 $37.78 538.32 $38.88 $39.08 $39.29 $39.49 $39.70 $39.91 36 Adjusted Regional bundled. $lmwh $102.30 $102.30 $102.29 $9676 $91.95 $92.56 $93.38 $93.47 $93.48 588.03 388.22 $88.63 569.07 $89.52 $89.08 500.44 N10.90 31 Lodi System Average Rale • Srmwh $97.91 $91.91 $97.91 $97.62 $9195 $92.56 $93.38 $93.41 $9348 $88.03 886 22 $8063 388.16 389.52 589,98 $90.44 590.90 -•. 0372971099 8:36 ALTERNATIVE 1 1282 2404 2491 2492 2041 2444 244@ 2448 2002 2448 2042 29.10 2411 2012 2011 2414 2911 DISTRIBUTIONINON-BYPASSABLE $31.35 $31.77 $36.38 $36.45 $36.36 $36.41 $16,43 $36.38 $37.44 $37.48 $37.47 $37.40 $39.38 $39.60 $39.76 $39.94 $40.11 TRANSMISSION ._.__. $9.92 $9.62 $9.72 $9.40 $9.64 $9.38 $9.29 $9.20 $9.11 $9.02 $8.94 $6.70 $10.61 $10.64 $10.72 $10.80 $10.87 GENERATION $56.64 $56.32 $30.49 $32.72 $33.84 $34.99 $36.19 $36.71 $37.24 $37.78 $38.32 $38.88 $39.08 $39.29 $39.49 $39.70 $39.91 CTC 54,114 14.44 121112 $48.12 11211 11.1.17 511148 1i11-iB f3 8@ Ua Li9B $3.82 14 40 59.40 14.9Il 14 44 $9 44 System Average Rate $97.91 $97.91 $97.91 $96.76 $91.95 $92.56 $93.38 $93.47 $93.48 $88.03 $88.22 $88.63 $89.07 $89.52 $89.98 $90.44 $90.90 COMPETITIVE RATE $102.30 $102.30 $102.29 $96.76 $91.95 $92.56 $93.36 $93.47 $93.48 $88.03 $88.22 $88.63 $89.07 $89.52 $89.98 $90.44 $90.90 Market Power $26.75 $28.42 $30.49 $32.72 $33.84 $34.99 $36.19 $36.71 $37.24 $37.78 $38.32 $38.58 $39.08 $39.29 $39.49 $39.70 $39.91 MVvH Sates 372,472 377,975 383,559 389,227 394,979 400,817 406,741 412,755 418.858 425,051 431,338 437,718 444,193 450,765 457,435 464,204 471,074 DISTRI LITIO INON.BYpgSSA@I,E 1024 2044 2041 2442 244,3 2049 2005 2000 2442 2048 2094 291.0 2911 2012 2413 20" 2015 Additional Stranded Cost Payment f $407 -$392 -$318 -$239 4161 Non -Operating Income -$810 -$834 $0 $0 $0 $0 $0 $0 $0 so $0 $0 $0 $0 $0 $0 $0 Interest Income 41011 -$939 $0 $0 $0 $0 $0 $0 $0 $0 SO $0 $0 $0 $0 $0 $0 Distribution Capital Debt Service $842 $918 $918 $1,355 $1,355 $1,355 $1,355 $1.355 $1,792 $1,792 $1,792 $1,792 $2,282 $3,160 $3,157 $3,158 $3,158 Distribution 08M $6.4B4 $6,646 $6,812 $6,982 $7,155 $7,334 $7,517 $7,704 $7,896 $8,093 $8,295 58,502 $8,714 $8,931 $9,154 $9,382 $9,615 Distribution Capital $6DO $618 $637 $656 $675 $696 $716 $738 $760 $783 $806 $831 5855 $681 $908 $935 $963 Public Benefits Expenses $1.001 $1,027 $1.016 $975 $958 $990 $1,010 $999 $1,016 $1,041 $1,049 $1,028 $1,015 $1,051 $1,068 $1,084 $1,101 General Fund Capital Load $350 $350 $350 $0 $0 $0 $0 s0 $0 $0 $0 $0 $0 $0 $0 $0 $0 General Fund Transfer S422 S422 14.220 S422 $422 14 220 14 220 S4220 t4 220 14.229 U22 3422 14.220 59.220 $422 19.220 19.224 $11,676 $12,006 $13,953 $14,186 $14,363 $14.594 $14,818 $15,016 $15,684 $15,929 $16,163 $16,373 $17,494 $17,851 $18,189 $18,540 $18,896 TRANSMISSION 1822 2444 2491 2442 2443 2049 2445 2406 2402 244@ 244.4 2414 2911 2412 2413 20]4 2416 Transmission Debt Service $928 $928 $924 $832 $962 $894 $891 $889 $887 $884 $882 $879 $668 $644 $642 $639 $637 Lodi Facilities Debt Service $0 $0 t0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $1,920 $1,950 $1,985 $2,015 $2,045 Transmission O&M slim 12107 32942 $2826 $2047 s2 867 SUR P -M U-10 $2 951 $2972 52459 12.126 52.244 32,224 V -W 32441 $3,696 $3,713 $3,730 $3,658 $3,809 $3,760 $3,778 $3,798 $3,816 $3,835 $3,854 $2,933 $4,713 $4,794 $4,905 $5,012 $5,123 GENERKION 1083 2444 200.1 2902 2003 2004 2905 2409 2042 2040 2048 2040 2M 2412 2413 2014 2415 MalkelGeneration $11,696 $12,737 $13,365 $14,025 $14,718 $15,152 $15,598 $16,057 $16,530 $17,017 $17,359 $17,709 $18,066 $18,430 $18,801 Lodi Generation 123AN 124.154 L4 -Z89 314 483 $10396 S10106 SLL428 111.3510 ;11.741 112.110 312.2`25 S12,48 312.678 312.876 113.078 S13 2Q2 113.491 Generation $23,489 $24,154 $11,696 $12,737 $13,365 $14,025 $14,118 $15,152 $15,598 $16,057 $16,530 $17,017 $17,359 $17,709 $18.066 $18,430 $18,801 9IG 1882 2444 2441 2442 2043 2449 2015 2440 2401 2448 2449 24]4 2411 24]2 2413 24]9 2415 Lodi Generation O&M $9,799 $10,093 $10,396 $10,708 $11,029 $11,360 $11,701 $12,110 $12,296 $12,483 $12,678 $12.876 $13,078 $13,282 $13,491 Market Generation :111-6 312.737 -S13.355 314025 314718 415,152 31j= _315 05I 31f.534 311.017 311.358 317.709 41S, 318.434 -31@ 001 CTC Offset -$1,896 -$2,644 42,969 -$3,317 -$3.689 .$3,791 -$3,897 .$3,946 -$4,234 -$4,533 -34,681 44,833 -$4,989 -$5,148 -$5,310 Non-Op6raling Income -$859 -$885 4911 -$939 -$967 -$9% 41,026 41,056 -$1,086 41,121 -$1,154 41,189 41,225 -$1,261 -$1,299 Interest Income 4792 -$681 4696 4652 -$588 -$531 -$522 -$513 -$369 -$237 4177 4158 -$136 4124 4126 Generation Debt Service $13.763 111.461 $1021 110 076 $11 029 110 111 $9 682 $9.912 19.777 S9534 56.374 $6231 S6261 $6249 16 271 CTC $10,216 $7,245 $6,634 $5,968 $5,785 $4,792 $4,235 $4,397 $4,086 $3,642 $0 $0 $0 $0 $0 $362 $51 -$88 -$284 -3464 Distribution O&M Distribution Capital Public Benefits Expenses General Fund Capital Loan General Fund Transfer CTC PG&E Distribution/Non-Bypassable Lodi Total MWH Sales ALTERNATIVE 1 18@8 212.44 2441 2942 21243 2444 244 24.48 2942 244@ 2448 2414 2411 2912 2413 2414 241@ $12.52 $12.89 $17.76 $17.94 $18.11 $18.30 $18.48 $18.66 $18.85 $19.04 $19.23 $19.42 $20.53 $18.94 $19.32 $19.70 $20.07 $3.67 $4.06 $4.05 $5.17 $5.14 $5.12 $5.09 $5.07 $6.09 $6.06 $6.02 $5.99 $7.06 $8.97 $8.89 $8.82 _. $8.75 $2.69 $2.72 $2.65 $2.50 $2.42 $2.47 $2.48 $2.42 $2.43 $2.45 $2.43 $2.35 $2.29 $2.33 $2.33 $2.33 $2.34 $0.94 $0.93 $0.91 $0.00 $0.00 $0.00 30.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $11.33 $11.16 $11.00 $10.84 $10.68 $10.53 $10.38 $10.22 $10.08 $9.93 $9.78 $9.64 $9.50 $9.36 $9.23 $9.09 $8.96 $0.00 $0.00 $26.63 $18.61 $14.26 $14.89 $14.22 $11.61 $10.12 $10.34 $9.47 $8.32 $0.00 $0.00 $0.00 $0.00 $0.00 $72.68 $71.01 $68.93 $54.69 $54.24 $53.64 $53.22 $52.74 $52.18 $46.00 $45.60 $45.43 $45.58 $45.73 $45.88 $46.03 $46.18 $31.35 $31.77 $63.01 $55.07 $50.63 $51.30 $50.65 $47.99 $47.56 $47.82 $46.94 $45.73 $39.38 $39.60 $39.76 $39.94 $40.11 372,472 377,975 363,559 389,227 394,979 400,817 406,741 412,755 418,858 425,051 .431,338 437,718 444,193 450,765 457,435 464,204 471,074 it im 2444 2491 2042 TRANSMISSION 2043 2004 2005 EXPENSE$ 200 - ALL 2992 CASES 209@ 2498 2919 2911 2912 2013 2014 24.11 ether Contracts $1.59 $1.51... $1.58 $1.58 $1.58 $1.57 $1.57 $1.57 $1.56 $1.56 $1.56 $1.55 $1.55 $1.54 $1.54 $1.54 $1.53 :OTP/SOT $2.57 $2.56 $2.55 $2.55 $2.54 $2.54 $2.53 $2.53 $2.52 $2.51 $2.51 $2.50 $2.50 $2.49 $2.49 $2.48 $2.48 nlerconnection $3.27 $3.23 $3.18 $3.13 $3.09 $3.04 $3.00 $2.95 $2.91 $2.87 $2.83 $2.79 $2.74 $2.70 $2.67 $2.63 $2.59 'G&E $4.15 $4.16 $4.16 $4.38 $4.44 $4.47 $4.51 $4.54 $4.58 $4.62 $4.66 $4.69 $4.79 $4.88 $4.98 $5.08 $5.18 03/29/1999 8:31 filename: FINALia ALTERNATIVE 1 REVENUES REGULATORY Distribution O&M Distribution Capital Distribution Debt Service Transmission O&M Transmission Debt Service Lodi Facilities Debt Service Public Benefits General Fund Transfer Market Generation TOTAL REGULATORY REVENUES TOTAL COMPETITIVE REVENUES TOTAL RETAIL REVENUES Non -Operating Income Interest Income TOTAL REVENUES 03/29/1999 8:38 EXPENSES Distribution O&M Distribution Capital Distribution Debt Service Transmission O&M Transmission Debt Service Lodi Facilities Debt Service Public Benefits Generation Debt Service Generation O&M General Fund Transfer TOTALEXPENSES BEGINNING FUND BALANCE Interest Income Excess Revenues/Revenue Deficiency ENDING FUND BALANCE 201]. 2012 2= 2014 2= $8,714 $8,931 $9,154 $9,382 $9,616 $855 $881 $908 $935 $963 $2,282 $3,1.60 $3,157 $3,158 $3,158 $2,126 $2,200 $2,278 $2,358 $2,441 $668 $644 $642 $639 $637 $1,920 $1,950 $1,985 $2,015 $2,045 $1,015 $1,051 $1,068 14.220 $1,084 $1,101 $4,220 $21,800 $4,220 $23,037 $23,411 $4.220 $23,791 $4.220 $24,180 _ $.17.359 $17,709 S1$,06$ $1$,430 $18,801 $39,159 $40,746 $41,478 $42,221 $42,981 $39,566 540,354 $41,160 $41,982 $42,820 $39,159 $40,354 $41,160 $41,982 .342,820 $1,154 $1,189 $1,225 $1,261 $1,299 $177 $168 $1$6 112A 5126 $40,490 $41,701 $42,521 $43,367 $44,245 2011 2012 2018 2Q14 2016 $8,714 $8,931 $9,154 $9,382 $9,616 $855 $881 $908 $935 $963 $2,282 $3,160 $3,157 $3,158 $3,158 $2,126 $2,200 $2,278 $2,358 $2,441 $668 $644 $642 $639 $637 $1,920 $1,950 $1,985 $2,015 $2,045 $1,015 $1,051 $1,068 $1,084 $1,101 $6,374 $6,231 $6,261 $6,249 $6,271 $12,678 $12,876 $13,078 $4220 $13,282 $13,491 54;220 $40,852 $4,224 $42,145 $42,750 $4.220 $43,322 $4.220 $43,942 $11,414 $11,488 $11,633 $12,000 $12,660 $436 $589 $596 $615 $649 -$362 .5444 -$220 545 5303 $11,488 $11,633 $12,000 $12,660 $13,612 Gen DS $6,374 $6,231 $6,261 $6,249 $6,271 Gen O&M $12.678 $12.876 $13.078 513.282 513.491 Total $19,052 $19,108 $19,339 $19,531 519.762 DETAIL OF STRANDED COST SUBSIDY PAID FROM RESERVES 2011-2015 (Zr r11 A11 Cost Subsidy Competitive Subsidy Add to Distribution O&M GENERATION 2011 2D12 2013 2014 2015 GENERATION Market Generation $17,359 $17,709 $18,066 $18,430 $18,801 Market Generation Lodi Generation $12.678 $12.876 $13.078 $13.282 $13.491 Lodi Generation Generation $17,359 $17,709 $18,066 $18,430 $18,801 Generation Generation Debt Service $6,374 $6,231 $6,261 $6,249 $6,271 Revenue Offset -$4,681 -$4,833 -54,989 -$5,148 -$5,310 Non -Operating Income -$1,154 -$1,189 -$1,225 -$1,261 -$1,299 Interest Income -$177 -5158 -$136 -$124 -$126 NET STRANDED COSTS $362 $51 -$88 -$284 -$464 Total Revenues $40,490 $41,701 $42,521 $43,367 $44,245 Total Expenses -$36.632 -$37,925 -$38,530 -$39,102 -$39,722 General Fund Transfer -54,220 -$4,220 -S4-220 -54,220 -54,220 COST SUBSIDY -$362 -$444 -$229 S45 $303 Distribution Debt Service $2,282 $3,160 $3,157 $3,158 $3,158 Distribution O&M $8,714 $8,931 $9,154 $9,382 $9,616 Distribution Capital $855 $881 $908 $935 $963 Public Benefits $1,015 $1,051 $1,068 $1,084 $1,101 General Fund Transfer $4,220 $4,220 $4,220 $4,220 $4,220 Transmission $4,713 $4,794 $4,905 $5,012 $5,123 Market Generation $17.359 $17.709 S18.066 $18.430 S18.801 $39,159 $40,746 $41,478 $42,221 $42,981 Sales 444,193 450,765 457,435 464,204 471,074 Lodi Average $88.16 $90.39 $90.67 $90.95 $91.24 Market Rate $89.07 $89.52 $89.98 $90.44 $90.90 COMPETITIVE SUBSIDY $407 -$392 -$318 -$239 -$161 COST SUBSIDY -$362 -$444 -$229 $45. $303 ACTUAL SUBSIDY $0 -$392 -$318 -$239 -$161