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1997-03-17 City Council
of Pal. Alto City Manager’s Report 9 TO: FROM: HONORABLE CITY COUNCIL CITY MANAGER DEPARTMENT: UTILITIES AGENDA DATE: MARCH 17, 1997 CMR:159:97 SUBJECT:Electric Utility Restructuring, Policy Guidelines Staff requests Council adoption of a resolution setting forth three policy principles that will guide the City’s actions concerning the restructuring of the electric utility industry in California. The Utilities Advisory Commission (UAC) voted unanimously to approve these policy principles, with certain revisions incorporated in this report. Customer Choice. The City of Pal. Alto Utilities (PAU) anticipates that competition among, electric power producers will bring efficiency and lower prices to the ultimate consumers. To provide Pal. Alto businesses and residents an opportunity to benefit from lower energy prices, the City believes that PAU customers should be allowed to choose their own power supplier. PAU intends to phase in customer choice over a period of time beginning on January 1, 1998, and concluding with all customers having a choice by December 31, 2001. Stranded Cost Recovery. Like many utilities that have an obligation to serve, PAU has made a substantial investment in power generation facilities and committed itself to long- term power supply agreements. These financial commitments were made in good faith to meet the long-range power needs of businesses and residents in Pal, Alto. Therefore, it is equitable that all customers pay their fair share of these investments, irrespective of who supplies their future power needs. To insure that the f’mancial integrity of PAU is maintained and to prevent cost.shifting, all PAU customers will contribute to paying the uneconomic portion of these investments in the form of a non:bypassable stranded cost recovery charge. The charge will be made explicit on customer bills beginning July 1, 1997 and adjusted annually to insure appropriate recovery of stranded costs. The stranded cost recovery charge will be discontinued on or before December 31, 2001, however, for residential customers it may be extended a few years in order to mitigate bill impacts during the transition period. CMR:159:97 Page 1 of 6 o Strategic Retail.Marketing. To maximize the use of its resources, PAU will explore opportunities to enhance the PAU’s revenues by extending its marketing efforts through the use of parmership or strategic alliances with power marketers to include retail customers residing outside the City’s service territory. RECOMMENDATIONS Staff recommends that the City Council adopt the attached resolution concerning the restructuring of the Electric Utility Industry in Califomia. P_POLICY IMPLICATIONS These recommended policies will have a substantial impact on the way Palo Alto acquires, markets and prices electricity. Approval of the attached resolution will initiate staff review of pertinent City governing doctunents (ordinances, policies, procedures, rate schedules, rules, regulations) to examine their viability to the ensuing competitive environment. Council approval of key revisions to the governing documents will be requested prior to the implementation of each policy. PAU intends to begin implementation of these policies on the dates specified in the policy statements. If events force adelay in the implementation schedule, staff will advise Council at the appropriate time. EXECUTIVE SUMMARY: Background. Historically, providing electric service has been viewed as a natural monopoly. A single vertically integrated utility generally has been authorized to serve electricity to a designated area. In return for that exclusive fight to market, the utility was obligated to deliver reliable electric services to residents and businesses within the designated service area. This meant that the utility was obligated to generate or acquire electricity, transmit that electricity using high-voltage transmission lines and then distribute the electricity to the customer site. In return for accepting these’ obligation, the appropriate regulatory agency allowed the utility to set rates to recover the expense of providing these services, together with a reasonable return on the utilities’ invested capital. During the last two decades, a sizable number of Independent Power Producers (IPPs) has entered the electric industry to compete with the vertically integrated utilities in the supply of electric energy. To promote competition in the electric supply business, the regulatory agencies (Federal and State).obligated the utilities to purchase power from IPPs when it was economically advantageous to do so; however, serving the retail consumer remained the ultimate responsibility of the utilities. In many eases, IPPs have sought to bypass the local utility altogether by installing electric generating plants on the sites of major industrial or commercial users. In 1992~ noting that electric rates in California are approximately 50 percent higher than the national average, the California Public Utilities Commission (CPUC) initiated a comprehensive.review of CMR:159:97 Page 2 of 6 the electric industry which culminated in April of 1994 with the initiation of a formal rule making proceeding to restructure the electric industry in the State.. During the summer of 1996, a joint conference committee of the California legislature commenced an intensive series of negotiations with respect to electric industry restructuring. These efforts culminated in the drafting of Assembly Bill 18901 (AB 1890) which was passed unanimously by both houses of the Califomia Legislators in late August 1996, and was signed ¯ into law by Governor Wilson on September 23, 1996. Among other things, AB 1890 directed the investor owned utilities (IOUs) in California to offer their retail customers the freedom to choose their supplier of electricity, sanctioned the electric utilities’ right to recover the cost of generating facilities that are no longer economical in the competitive market place and permitted utilities to market electric supply in each other’s service areas. An information summary of AB1890 was provided to Council on September 26, 1996 (CMR:411:96). Although AB 1890 is the first comprehensive electric industry restructuring legislation passed by any State, major industry restructuring proposals are also pending in New York, New Jersey, Illinois, Maine, Pennsylvania, Rhode Island, Michigan, Arizona and Wisconsin. Customer Choice. The passage of AB 1890 concluded the effort that the industry stakeholders (IOUs, municipal owned utilities, state and federal regulatory agencies, associations representing customer’s interest, environmental groups, energy marketers and brokers, independent power producers, etc.) began in April 1994. It is now a matter of law that some customers who are being served by IOUs in California (75% of the California market) will have the right to choose their own power supplier by January 1, 1998, with all IOU’s customers having choice by December 31, 2001. While AB 1890 gives municipalities the option not to participate in the industry deregulation, it will be. extremely difficult from a political standpoint to deny the City electric customers the same fight given to the IOUs’ customers. Furthermore, staff believes that the opportunities and benefits that open competition will bring to the City will exceed the potential loss of some customers to the competition. In any event, by providing the direct access option, Palo Alto residents and businesses will have an opportunity to control their energy costs which otherwise may not exist. To seize the opportunities that competition will bring, PAU has reduced expenditures, established a strong f’maneial position, adopted a program to market supplies and services to the city’s key accounts, and implemented a new process of acquiring supplies to ensure a speedy response to customer demand. In addition, staff is developing a new customer information system (CIS) to enable the PAU to offer new rate and service options and improve business processes. Currently, PAU’s cost of acquiring electricity is very competitive. Staff believes ¯ that in the future, PAU can continue to acquire resources and provide energy services at very competitive prices. CMR:159:97 Page 3 of 6 Generally speaking, PAU has three options regarding the timing of offering customer choice. One option is to begin on January 1, 1998 when the California IOUs are required by AB1890 to provide customer choice. The second option is to start no later than January 1, 2000, to receive benefit from the State sanction of stranded cost recovery provided for in AB 1890. This slower pace of implementing customer choice will allow up to two more years for PAU to acquire the systems and expertise necessary to enter into a competitive market and to learn from any mistakes that the IOUs and other competitors may make in their rush to acquire market share. However, staff believes that utilities entering the competitive market on January 1, 1998 will preempt competitors and thereby have a decided advantage. Furthermore, choosing a slower pace may cause customers to suspect the City’s ability to compete in the market place. A third option is not to provide choice to Palo Alto’s electric customers. This strategy would maintain PAU’s monopoly on supplying electric power to City residents and businesses. This strategy may be circumvented by Congress which will be debating four different bills dealing with the restructuring of the electric.utility industry in 1997. These bills, unlike AB 1890, are likely to mandate open competition to all utilities including municipalities. In addition, customers, especially industrial customers, have been vigorously pursuing open competition and. could consider legal action if their political efforts are fruitless. Therefore, staff believes and recommends that PAU offer customer choice simultaneously with the IOUs of California. This would maintain .the superior position that PAU has enjoyed over the years when compared to the California IOUs and will increase customer confidence in PAU’s ability to compete for their business. Stranded Cost Recovery. Over the years,, electric utilities including the PAU have made sizable investments in building and contracting for generating ~facilities, driven by their obligation to serve and their guaranteed market share. Several of these investments, especially those made in the early 1980s, have proven in retrospect to be uneconomical: To ensure fair competition, regulators and legislators have acknowledged the right of the utilities to recover the uneconomical portion of these investments from their current customers. To successfully and competitively serve the PAU customers, it’s important that PAU make explicit the recovery of its stranded costs. PAU has made certain investments in the Calaveras hydroelectric project and the California-. Oregon Transmission Project. A high percentage of both investments, by today’s standards, is considered uneconomical. AB 1890 has sanctioned the municipalities’ right to recover and collect stranded costs during progression to full competition. PAU expects that its stranded costs will be considerably lower than that of Pacific Gas and Electric and many California municipal utilities. Following the transition period, it is expected that Palo Alto customers would be offered a rate decrease reflecting the conclusion of stranded cost collection. CMR:159:97 Page 4 of 6 In recognition of the need to recover stranded costs, the City Council approved a Calaveras Reserve Policy during the budget process last year (CMR:214:96). More recently, staff revisited the stranded cost issue with the UAC resulting in a revised target balance and time schedule to build up the Calaveras Reserve. This information, including a proposed rate increase for FY 1997-98 will be presented to the Council during the FY 1997-98 budget process. Strategic Retail Marketing. Over the years PAU has nurtured valuable technical and marketing expertise to meet the customers’ needs. As markets become more competitive, the PAU must continue to expand upon those efforts and offer custom tailored products and services to ensure customer satisfaction and loyalty. Offering options and services similar to those offered by the City competitors will help PAU hold on to its market share. However, when customer choice is offered, PAU should be prepared to lose some of its customer base. PAU could mitigate the potential customer loss by first expanding sales and services to existing customers and second, by serving retail customers outside PAU’s traditional retail service territory. Expanding power retail services beyond PAU’s boundaries will maximize the use of PAU’s assets. Staff believes that PAU can leverage its assets to provide long-term supplies and risk management services beyond the Palo Alto borders. Given the level of effort required to market power to retail customers at-large, the most efficient and effective way to market supplies and services beyond the border is to form partnerships with power marketers. An example of partnerships is the NCPA/ENRON Agreement (CMR: 125:97). PAU has certain assets and fights that could prove attractive to potential partners. These assets include 50 Megawatts of the Calaverashydroeleetric project, 50 Megawatts of the California- Oregon Transmission Project, a long-term contract with Western Area Power Administration and certain rights under the NCPA intereormeetion agreement with PG&E including area transmission, and ancillary services. Power marketers have staffing and risk management expertise that could provide PAU with better access to other markets, and also to prepare PAU to offer similar services to our existing customers. FISCAL IMPACT While approval of these policies will have no significant immediate impact on the Utilities budget, the following is the most likely scenario addressing financial impact on the industry in general and Palo Alto in particular: 1.Sales revenue for PAU will increase between 1998 and 2001 reflecting the rate increase needed to mitigate stranded costs and potential sales outside of Palo Alto. 2.By 2001 revenues will decrease to reflect the reduction of stranded cost collection. 3.Pricing for commodities will be market based while pricing the delivery (transmission and distribution) will’ remain to be cost based. The margin from eornmodity sales will be CMR:159:97 ’Page 5 of 6 extremely slim until the turn of the century. At that time, the City’s largest supplier (the Western Area Power Agency) will become more competitive with the market place. 4.Expenditure on marketing activities will increase substantially to mitigate competitive pressures and to promote the City utilities’ brand name. ENVIRONMENTAL ASSESSMENT These policies do not constitute a project for the purposes of the California Environmental Quality Act. ATTACHMENTS. Resolution Re Approval of Policies Concerning the Restructuring of the Electric Utility Industry, CMR: 125:97 Info Report on Agreement between NCPA and ENRON to pursue opportunities as partners, January 1997, UAC Report Policy Statements to maintain the electric utility’s competitives, December 1996, and UAC Minutes, Three reports and minutes to UAC on Stranded Costs, analysis and funding strategy, November and December of 1996 and January 1997, CMR:411:96 Summary of California Legislature’s Electric Restructuring Bill AB 1890, September 1996, CMR:214:96 Proposed Electric Fund Calaveras Reserve Policy, April 1996. PREPARED BY: Tom Habashi, Assistant Director of Utilities, Resource Management DEPARTMENT HEAD APPROVAL: CITY MANAGER APPROVAL: cc: Utilities Advisory Commission EDW Manag~ CMR:159:97 Page 6 of 6 RESOLUTION NO. RESOLUTION OF THE COUNCIL OF THE CItY OF PALO ALTO CONCERNING THE OPTION OF THE CITY’S ELECTRICITY CUSTOMERS TO ENGAGE IN DIRECTTRANSACTIONS WITH ALTERNATE POWER SUPPLIERS,THE CITY’S RECOVERY OF ITS UNECONOMIC INVESTMENTS IN ELECTRIC GENERATION FACILITIES, AND THE CITY’S MARKETING OF PRODUCTS AND SERVICES TO CUSTOMERS OUTSIDE OF THE CITY’S JURISDICTIONAL BOUNDARIES IN THE CONTEXT OF THE RESTRUCTURING OF THE ELECTRIC UTILITY INDUSTRY IN CALIFORNIA WHEREAS, the restructuring of the California electric utility industry has been driven by changes in federal law intended to.create competition in the provision of electricity, and, under Assembly Bill Number 1890 ("AB 1890"), the California legislature adopted a legislative foundation for transforming the regulatory framework of California’s electric industry; and WHEREAS, AB 1890 sanctions the right of municipalities, including the City of Palo Alto ("City"), to collect a nonbypassable generation-related severance fee or transition charge from its electricity customers, and requires the municipalities~to permit direct transactions between the municipalities’ electricity customers and alternate suppliers of electricity if such fees or charges are collected; and WHEREAS, the city wishes to authorize direct transactions between alternate suppliers of electricity and its electricity customers and the collection of a nonbypassable generation-related severance fee or transition charge from these customers; and WHEREAS, the City may wish to mitigate its potential losses ~of electricity revenues by Offering products and services tO electricity customers outside ’of the City’s jurisdictional boundaries, to the extent this is legally and administratively feasible; NOW, THEREFORE, the Council of the City of Palo Alto does hereby RESOLVE as follows: SECTION i. The City Council finds that the restructuring of the electric industry in California will engender substantial competition among electric power suppliers, and, as a consequence, lower prices for electricity may be offered. The Council further finds that the City in good faith invested substantial amounts of money, inthe acquisition or development of long-term power supply resources, which now are proving to be uneconomical in view of the substantial decrease in the current wholesale prices of electricity. The Council takes notice of Assembly Bill number 1890, which permits the City to authorize direct transactions between the City’s electricity customers and alternate suppliers of electricity and to recover the costs of its uneconomic investments in generation facilities from the City’s electricity customers° 1970227 syn 0071131 SECTION 2. The City Council declares that it is in the best interests of the City to permit its electricity customers to engage in direct transactions with~ alternate suppliers of electricity and collect nonbypassable generation-related severance fees or transition charges from its electricity customers, and it hereby authorizes the City Manager or her designee to collect and secure from the City’s electricity customers nonbypassable generation-related severance fees or transition charges and written confirmations of their obligations to pay such fees or charges. SECTION3. The City Council further declares the City may authorize the offering of certain financial’ and non-financial products and services to its electricity customers residing outside of the City’s jurisdictional boundaries, provided that it can be established to this Council’s satisfaction that the interests of the City will be served by the offering of these products and services, and it is legally and administratively feasible to engage in such transactions. SECTION 4. The’ City Manager is hereby authorized to conduct a thorough review of the relevant laws, rules, regulations,. rates, policies and procedures~which may bear directly upon the City’s rights and obligations with respect to its electricity customers as the electric industry is being restructured, and make recommendations of such new and revised laws, rules, regulations, rates, poli~ies and procedures to this Council as Will effectuate the foregoing statements of policy. SECTION 5 The Council finds that the adoption of the following policies does not constitute a project for purposes of the California Environmental Quality Act, and, therefore, no environmental assessment is required. INTRODUCED AND PASSED: AYES: NOES: ABSENT ABSTENTIONS: ATTEST:APPROVED: City Clerk APPROVED AS TO FORM: Senior Asst. City Attorney Mayor City Manager Director of Utilities Deputy City Manager, Administrative Services. 2970227 syn 0071131 City of Palo Alto City Manager’s Report TO:HONORABLE CITY COUNCIL FROM:CITY MANAGER DEPARTMENT: UTILITIES DATE: SUBJECT: January 23, 1997 CMR:125:97 Agreement between NCPA and ENRON to Pursue Partnering Opportunities REQI~ST This report is informational only. There are no recommendations and no Council action is required. This report requests no actionat this time and therefore has no policy implications. Over the last fourteen’months, the Northern California Power Agency (NCPA) had informally . contacted various power marketers and utilities to discuss working together, to pursue mutually economic power supply and marketing opportunities unfolding parallel to the restructuring of the California utility industry. This process became formalized in February 1996 through NCPA’s Strategic Planning process that concluded in August 1996. NCPA Was directed by their Commission to work with all member utility Directors, including City of Palo Alto’s Utilities Department Director, to seek strategic partnering, opportunities to remain competitive with the advent of electric deregulation. Three broad objectives were sought through partnering: 1) more efficient utilization of existing power assets; 2) cost reductions through joint operations; and 3) marketing assistance and product development to serve new and existing loads in northern California. The ultimate goals are to lower costs to NCPA’s existing members, and to erdaanee members’ competitive positions in existing service territories. ClVIR:125:97 Page 1 of 3 In August 1996, NCPA issued a Request for Proposal (RFP) to solicit partnering interest in specific areas of potential joint economies. Eight companies responded to the RFP; and NCPA Commissioners, at their September board meeting, approved further formal investigation of partnering approaches that could potentially strengthen NCPA and its members’ competitive positions. Four of the most promising RFP respondents, including a California Investor Owned Utility (IOU), a Pacific Northwest IOU, a natural gas and power marketer, and a California- based independent power producer (IPP), were interviewed by the member utility Directors. In November and December 1996, the four entities underwent formal questioning about how they proposed to work with NCPA and its members to jointly benefit from electric power deregulation. By a unanimous vote of the Utility Directors on December 18, 1996, ENRON Corporation was selected to pursue joint opportunities with NCPA and participating NCPA members. This decision was then confirmed at a special NCPA Commission meeting on January 8, 1997, where board members voted unanimously to form a strategic alliance with ENRON Capital and Trade Resources, a subsidiary of ENRON Corporation. The NCPA/ENRON agreement is the first of its kind in California and is a proaetive response to Assembly Bill 1890, the new law passed last September deregulating the electric power industry in California. This alliance is designed to offer improved energy services to customers while positioning NCPA and its member agencies to successfully compete in a restructured electric service industry. This partnership will allow NCPA and ENRON to work jointlyto more efficiently manage power supply and energy sales, to operate more effectively in the new customer-driven marketplace now taking shape in California, and to extend utility services to new customers.. ENRON is one of the world’s largest integrated natural gas and electricity companies, with approximately $15 billion in assets. NCPA will benefit from ENRON’s experience and success in dealing with the transformation of the natural gas industry over the last decade, as well as its industry leadership in developing finaneiaYrisk management products specifically tailored to the electric industry. These strengths, coupled with a strong balance sheet, an innovative, "can-do" corporate attitude, and the ability to quieldy adapt to the changing power environment, make ENRON a desirable partnering Candidate for NCPA. ENRON also demonstrated strong corporate commitment to provide necessary resources and staff to work with NCPA and its members to achieve success in the new California power world. When final contractual agreements are approved, ENRON will provide a comprehensive package of services to NCPA and its members. NCPA and ENRON together will seek and develop new electric loads outside NCPA member service areas. These new loads will be served through the market and existing NCPA resources. Member utilitie~ will have the option of selecting the specific service offerings most beneficial to their service area. These services will likely include the sale of natural gas to member customers being served by PG&E; the purchase of electricity from ENRON when needed; the sale of excess power to ENRON when available; development of customer.metering, billing systemsand other systems for existing NCPA CM~:125:97 Page 2 ot’3 " customers; the design of, and accounting for, new gas and electric loads; and financial and risk management products. FISCAL IMPACT No recommendations are contained in this report and there is no fiscal impact. ENVIRONMENTAL ASSESSMENT This informational report does not constitute a project under the California Environmental Quality Act; therefore, an environmental assessment is not required. ATTACHMENTS NCPA’s press release NCPA/ENRON Final Agreement PREPARED BY:Linda Clerkson, Coordinator, Utility Marketing Services DEPARTMENT HEAD APPROVAL: EDWARD J. MRIZEK Director of Utilities CITY MANAGER APPROVAL: CIVIR:125:97 Page 3 of ¯ NCPA Northern California Power Agency 180 Cirby Way, Rosevllla California I]5~78 MICHAEL W. McDONALD General Manager (91{5) "/g 1-4200 January 15, 1997 TO: NCPA Commissioners and Utility Directors SUBJECT: NCPA - ENRON Major Strategic Energy Alliance Press Conference Today, the North~’fi Califo~:tti~t’PoWer-Agen¢y a ~bsidia~ orEgON Co~or~io~ ~oun~ the ~ion ofast~e~c ~i~de~ to offer impm~d ener~ s~c~ to.su~omen ~le positio~ng N~A ~d i~ ~er ~es to su~s~lly ~mpete in a ~tm~ur~ ~c ~ induu~. ~ p~s~p MII ~low NCPA ~d E~ON to work joindy to more effectively ~e pow~ sup~y ~d ~ ~es, ~d to ~end utility se~s to new ~~s. A ~py of the pros ~o~ent ~d other info~tion is a~ach~. The conference was attended by myself, ENV.ON Corporation President and Chief Operating Otfiver .left Skilling, and Mark Nelson of Hewlett-Packard Company in Roseville. Mark Nelson’s comments about the agreement highlighted the press conference:-"This alllan~e has the potential to be very positive for all residents in these communities, including community businesses. Our vision is to continue to enjoy the outstanding service and reliability provided by a ¯ locally managed and controlled municipal utility, and combine that with co~ts which are competitive with the market, predi .~c~!e and stable.". ;:!.., ,,,...:: Please call either myself at the above phone number or l~oger .Fontes at NCPA at (916) 781-4203, if you have any questions about the alliance br t[~e press Conference. Sincerely, MICH/~L W. McDONALD ’ RAF/dg Attachments News Release FOR.IMMEDIATE ~ASE: ~anuary 15, 1997 ~cnt ~~.and ~, one of ~ w~d’s ~ ~~ly $1~.~ioa will develov customer ~S, billing ,syst~as and ~er sysmms, for ~ NCPA cus~om¢~ and for ~ d~~t and ~~ ~ ~ gas and elec~ic loans . Benefits from NCPA/E~O~ Agreemen~ and. b~ner produc~ ~’o~ custornc~ Lowcr ottc~ ~ ~ of Imw~r WALL. STREET . © t~7Do~ J~ ~ ~wy, Y~ J~ ~ l¢~ " we.~,~ WEDNESDAY, JANUARY 1.~, 19~7 BUSINESS .BRIEFS Involving 11 In Cahforma By Pm’~ ~ ¯ ~ Co~. b e~ct~ ~ announce ~y a ~mt¢bi~-~nd ~i~ce ~ ~e ene~ ~ of tl No~em ~ifor- ~ for other publi~p~vate p~er- ~s in a de~at~ elec~ci~ merket. fo~a ~er A~n~ ~ ~age ~e a~n~’s ~wer supp~ and ene~ ~les. N~A is a nonprofit utill~ a~n~ fo~ In 1~ ~ gene~te, ~nsmlt and ~bute d~ic~..[~ ~e ~ ~ude~ cit, i~ i~e ~o ~ ~d ~ like N~A. ~he a~ncl~ fa~ ~e p~ lin~ ~ ~-p~ sales. A~ ~dere~e- Uon ~ ~ egen~ ~ io~ ~mem~ l~er ~~, ~ey ~d ~ve 1~ ~venue for e~er ~ ~c~, eu~ ~ ~a~e pinup ~ ~ ~p~. .. ’~ ~ a ~e whe~ a ~ent mono~ly p~d~r ~ I~ng for ou~ide, p~v~ ~ismnce ~e~e i~ ~mmem," ~d Enmn ~s~t J~f~ ~ S~Hing. "It’s a new idea In ene~ ~nagement we e~ to ~u~ elsewhere." To ~e NCP~ ~ vent~e ~ Enmn ~ a defensive mo~ a~in~ P~c O~ ¯ Electric Co. PG&£ currently provides nat- ural gas to lq~’A customer~ and b ex- pected to compete as a seller of electricity as deregulation evolve~. With ~’on, the NCP~ gal~ ~other potential ~s provider to compete with PU~E. For Znron, t~,Ski]ling said, the ance reprezents the belief that the best way for ]Zm’oe to ~mpete for retail cus- tomers-is to work with local energy pro.’ videz~ instead of vying directly foi" their customers, the approach taken .by Spent Corp, and MCI.COrp. after the breakup AT&T Corp. In.addition to incre~ed rai-ra~ sales, E’nron will provide risk.man- agement and other financial product~ to ).Longer term, £nron Impes the deal All be]p It develop brand-name recognition .that It can parlay Into other consumer business oppcrtun|ties. ¯ l~oward I~t end, £nron unveiled yes- terday its first major advertis|ng~to ma~e the comp|my a house- d name. ]n five yearz, Enron plans to¯ zpehd over $200 million a yeaz selling Its corporate Imageand the idea o! chopper ener~, In a de~e~qdated world, In m~ny ways, C~lffomi~ bthe pe~ect laboratory .lot companies hoping to do business in dere~dated energy, With elec- tric z~tes ~/~ higher ~ the average, the state l~ moving quicMy to open the m~’ket to competition and help spell the state’s economic ~ovez’y... F.RO~ E~F LEGAL (TUE~ O i. ’" 97 ’ ". ~7:58/ST. 17:57,,~0. 3551646597 P 2/4 po~ur supplies and w.r~’icc~ ma) Ix: prou~d~ to dvJ;r ~$p~’liw an~ prosp~ivc n~mb~rs and ~atomcra wilhin an incr~a~ing|y compcriowJ cnvimnntcnL ENILON may, ¢ifl~cr individually or in onon. sock emd ~,vclop oppartunkies v,~icl~ may bc s~,’tvcd, i, park by NCPA and ENKQN aupplicd capael~y, ermr~’ mid ~la~ed energy, and financial NOW, THEREFORE. in consldcra.o, of d~ momal pmmisc~ hur¢,nb¢lmv s~l ~’th, and ,~r and valuably ¢on~k~,mn. ~hc rccc~pt and adcquac)’ ~ich i" hc~by ackno~l~l/~d. NCPA m~d ENRON The Pani~ v, dl nc~o[m~ m good faid~ m d~vclo~ one or more aBm~,’nm~tz m mclud~ d~ f’o~lowm 8 princ~pk."s, m,nong otl~r’~: , NCPA amf ENRON ~dl. x,t,~n eco~mically advanlai~us, =oopcm0vciy dc.w,~Op and mark= pmduc= and ~=n4~= for d~ir r~p~li~ and pmsp~cUv~ r~mb~s aad cullomcm. FRO~ EC~ L£GAL :, ,. ~ ’ ’646591 ? 3./4 4 7 Thin l~gn:emcm d~ll be gavc~tcd bF and onfined m ~.orcEm~ wid, ~ b~, ~m I~,~g juri~d~ion ~,4~m d~ St~ of C~li~omiu. ¯~46~g~ P 4/4 other stmilsr W]THESS TIlE SIGNATURES OF THE PARTIES’ DULY AUTHORIZED OFF|CE!~ A~; OF TIlE DATE SET FORTH ABOVE NORTHERN CAI,,IFORNIA POWER AGENCY B,~: ~ ~ "v~,: ~-~...., ..... M,dm~l ~. McOo~d " ’ ~- ..............." ...."" "":" G~I M~ur ....~ ,~ , .,’: .......... . ,i~ i,~ ~":..~. M~u~iag Dirccaor : -- 3 7. b MEMORANDUM TO: FROM: AGENDA DATE: SUBJECT: Utilities Advisory Commission Utilities Department December 4, 1996 Approval of Policy Statements to Maintain. the Electric Utility’s Competitiveness REQUEST, This report requests that the UAC review and r6commend that the City Council approve the following policy statements to keep the Electric Utility competitive as the electric utility industry is deregulated. RECOMMENDATIONS Staff recommends that the UAC review and recommend City Council approval of the following three policy statements: 1. Customer Choice. The City Palo Alto Utilities (PAU) acknowledge that competition among electric producers will bring efficiency and lower price to the ultimate consumers. To provide Palo Alto businesses and residents an opportunity to benefit from lower energy prices, PAU customer’s will be allowed to choose their own power supplier. PAU intends to phase-in customer choice over a period of time beginning January 1, 1998 and concluding with all customers having a choice by June 30, 2002. 2. Stranded Cost Recovery. Like many utilities that have an obligation to serve, PAU has made substantial investment in generating facilities and committed itself to long-term power supply agreements. These financial commitments were made in good faith to meet the long-range power needs of businesses and residents in Palo Alto. Therefore, it is equitable that all customers pay their fair share of these investments, irrespective of who supplies their future power needs. To insure that the financial integrity of PAU is maintained and to prevent cost shifting, all PAU customers will contribute to payingthe uneconomic portion of these investments in the form of a Competitive Transition Charge (CTC). The CTC will be made explicit on customer bills beginning of July 1, 1997 and adjusted annually to insure appropriate recovery of stranded costs. The CTC will be discontinued on or before July 1, 2002. 3. Strategic Retail Marketing. To maximize the use of its resources, PAU will explore opportunities to enhance the PAU’s revenues by extending its marketing efforts tba’ough the use of partnership or strategic alliances with power marketers to include retail customers residing outside the City’s service territory. POLICY IMPLICATIONS Implementation of these policy statements will allow the City’s electric customers a choice in their power supplier. The policies will also allow the PAU opportunities to explore and recommend appropriate ways to provide services to new markets. EXECUTIVE SUMMARY" Customer Choice. Since April, 1994 staff has provided the UAC with periodic updates on activities dealing with the restrncturing of the electric utility industry at the State and the National level. The passage of California Assembly Bill 1890 with a unanimous vote culminated the effort that the industry stakeholders (investor owned utilities, municipal owned utilities, state and federal regulatory agencies, associations representing customer’s interest, environmental groups, energy marketers and brokers, independent power produce’rs, etc.) began in April 1994. It is now a matter of law that customers who are being served by investor owned utilities in California (75% of the California market) will have the right to choose their own power supplier by January 1, 1998. While AB 1890 gives municipalities the option not to participate in the industry deregulation, staff believes that it will be extremely difficult from a technical, economical and political stand point to deny the City electric customers that same right. In preparation for deregulation, PAU has been working to reduce expenditures, adopted a program to market supplies and servicesto the City’s keyaccounts, and implemented a new process, of acquiring supplies to ensure a speedy response to customer demand. In addition, PAU is developing a new customer information system and will be recommending that electric rates be unbundled. Currently, PAU’s cost of acquiring electricity is very competitive. Staff believes that in the future, PAU can continue to provide energy services at very competitive prices. PAU has two options regarding the timing of offering customer choice. One option is to begin on January 1, 1998 when the California IOU’s are required to provide Customer choice. The second option is any time after January 1, 1998 with a date no later than January 1, 2000; 2 years after the IOUs begin offering retail, competition, as mandated by AB 1890. While this second option provides PAU up to two years more time to acquire the systems and the expertise required to enter into a competitive market, staff believes utilities that enter the competitive market on January 1, 1998 will preempt competitors and would be able to hold’on or acquiring market share. 2 staff believes and recommends that PAU should offer customer choice simultaneously with the Investor-Owned Utilities (IOUs) of California. This would maintain the superior position that PAU enjoyed over the years when compared to the California IOUs and will increase customer’s confidence in PAU’s ability to compete for their business. Stranded Investment. Over the years, the PAU have made sizable investments in building and contracting for generating facilities, driven by their obligation to serve and their monopolistic. guaranteed market share. Several of these investments, especially those made in the early eighties, have proven to be uneconomical.. To ensure fair competition, regulators and legislators have acknowledged the right of the utilities to recover the uneconomical portion of these investments from their current customers. PAU has made certain investments in the Calaveras hydroelectric project and the California-Oregon Transmission Project. A high percentage of both projects, by today standards, are considered uneconomical. To successfully serve the PAU customers, it’s imperative that PAU’adopts a policy to make explicit the recovery of stranded investments. AB 1890 has endorsed that concept and sanctioned the municipalities’ right to collect a Competition Transition Chat’ge during progression to full competition: PAU expects that its CTC will be lower thian that of Pacific Gas and Electric, the IOU serving the surrounding communities. A rate increase will be required to build up a "Stranded Cost" reserve fund to a level sufficient to pay for the uneconomical investments after the transition period. Following the transition period, it is expected that customers would be offered a sizable rate decrease reflecting the conclusion of CTC collection. Strategic Retail Marketing. PAU’s primary focus is to provide low-cost reliable service and to meet the needs of existing retail customers. As markets become more competitive, the PAU must continue to expand upon those efforts and offer Custom tailored products and services to ensure customer satisfaction and loyalty. Offering options and services similar to those offered by the City competitors will help PAU hold on to its market share. However, when customer choice is offered, PAU should be prepared for losing some of its customer base. PAU should mitigate that potential customer exodus by expanding sales and services to existing customers and forming strategic alliances to serve retail customers outside PAU’s traditional retail service territory. Expanding po~ver retail services beyond PAU’s traditional boundaries will maximize the use of PAU’S assets. Staff believes that PAU can leverage its assets to provide long-term supplies and risk management services beyond the Palo Alto borders. Given the level of effort required to market power to retail customers at-large, staff believes that the most efficient and effective way to market supplies and services beyond the border is to form partnerships with power marketers. PAU has certain assets and rights that could make us attractive partners for power marketers. These assets include 50 Megawatts of the Calaveras hydroelectric project, 50 Megawatts of the California-Oregon Transmission Project, long-term contract with Western Area Power Administration and certain rights under the NCPA interconnection agreement with PG&E including area transmission, and ancillary services. Power marketers have staffing .and risk 3 management expertise that could provide PAU with better access to other markets, and also to prepare PAU to offer similar services to our existing customers. Next Steps Upon UAC approval, staff will forward these policy recommendations to the City Council early in 1997. An implementation plan, of those policies approve.d by Council, will be ¯ presented to the UAC in ~he near future. PREPARED BY: Tom Habashi, Assistant Director of Utilities DEPARTMENT HEAD APPROVAL: EK. of Utilities CITY MANAGER APPROVAL: 4 confidential information, because they showed something about our process~\It could showwhat it-was we were planningit~ do, such as how much wate~ we bought as. opposed to how much deioniz~d water. That would tell someone what they were doing with it.Simil~ly, in Palo Alto, how your information is metered, how your is metered, is a relevant iss~, because you might be able to who the customer was by figuring ou~ how many meters they had where the meters were or what size the meters were. So in the mode Paul is suggesting that consumption info~tion is available your name is not, you would have to be clear tha~. you did not tell enough so that they could figure out who the~was, an~did not release information that the company might~confidential for legitimate reasons about the ratio of what someone else’s usage. Mr. Calonne responded to Commission and received commission comments. Mr. Calonne: I do not disa~: business side, I think the policy and procedure, but were, that gives us some That goes a long way in Chairman Johnston: look further into a c I think just to tip the hand on the of implementation will not only be a addendum to the service agreement, as it ~dence of the company’s concern. you very muo~. I understand you wanted to of items and wi~ come back to us again. Mr.Calonne: Answered Yes, I would like to come back. I have really / appreciated youri~omments~_/__ You have raised a ~umber~ of issues that I would like to,.~espond~ before I ask you for a ~ecommendation,,~ to the. council. Chairman J6hnston : Item 7. B. Thank you very much. Deregulation of Electric ~ndustr3r Proposed Policies. Mr. Mrizek: Said for more than two-and-a-half years now, staff has been discussing with the Commission periodically what has been happening in the restructuring of the electric industry. During that time, staff ~also has been working to strategically position the electric utility where we will continue to be compet~itive in a deregulated environment° AB 1890 is now law, and it establishes specific dates for investor-owned utilities to allow their customers a choice. It also provides options for municipal utilities to provide their customers with a choice. The policy statements we bring to the Commission requesting your approval will give the electric customers in Pa!o Alto the same choice as the investor-owned utilities. This is specifically what we are requesting MINUTES UAC:12/04/96 FINAL PAGE 45 in Policy Statement #i, Customer Choice. Policy Statement #2, Stranded Cost Recovery, is basically making explicit Competitive Transition Charges (CTC) to put on customer bills, beginning July i, 1997. Randy has been bringing reports to you on the CTC. Early next year, he will continue that process. We are recommending that a CTC be established and that it end no later than July i, 2002. The third policy statement we are requesting is what we call Strategic Retail Marketing. This is going to allow staff the opportunity to explore other revenue potential outside the City’s current service territory, which is within the City limits. We are proposing in this policy statement to do this by forming partnerships or strategic alliances with power marketers to explore serving our retail customers in other areas of the state. We are asking the Commission to approve these policy statements so that staff can move forward and carry these recommendations to the City Council, then plan to provide our customers with choice by January i, 1998. As the report indicated, we could delay this for two years, but staff does not believe that delay is appropriate, we believe we should stay on the s~me schedule as the investor-owned utilities to give us the same advantages they have in the marketplace. We are ready to answer any questions that the Commission may have. Commissioner Eyerly: Said I think the three points that you have brought us, Ed, are entirely appropriate.It. seems to me that we have discussed all of this a number of times.Over the last few months, staff has brought us these issues, so I find ~nothing wrong with the recommendations. Commissioner Sahagian: Said In principle, the recommendations all look good to me. I have a Couple of.questions and comments .to submit. First off, regarding stranded cost recovery, I think we should make it clear that it is a non-bypassable competitive transition charge. I think that is the intent, and we should probably spell it out. On that same policy statement, we talked earlier about possibly aligning the end of the CTC with the beginning of 2002. It says "before." It does not preclude that, but it might be better to be explicit on that point. I was curious about Policy #3, Strategic Retail Marketing. You suggest aligning either strategic alliances or usingpower marketers on a third- party power base to help us expand our service territory. .My immediate reaction was, why not go it alone? Why risk bringing in third parties who could potentially be brokering for others, as well, as opposed to maintaining control of that function ourselves, building the capability in-house. That is something I question. MINUTES UAC: 12/04/96 FINAL PAGE 46 Mr. Habashi: Said The idea was that we would combine our assets with those of the power marketers. Right now, wehave certain assets in the Calaveras project, transmission rights, our contract with Western, etc. They have a lot of experience in financial transactions and risk management abilities. We would like to be able to work with someone else who has that kind of expertise. Besides, some of those marketers have portfolios that go considerably beyond what we have right now. So for example, if we wanted to work with Hewlett-Packard to supply their campuses throughout the bay area, that would be way beyond our ability. But if we are working with a marketer who has a portfolio of resources, we probably could do that by perhaps using some of our transmission rights and some of the marketer’s resources, combining those in order to put together the best deal for Hewlett-Packard. Commissioner Sahagian: Would we be seeking some kind of non-competition or protection if we were to’enter this type of alliance? I think that would be very important, because there are two edges to the sword, ~f you go ~forward with this strategy, which could be a very good one. There can be a flip side to that strategy that I think we should address somewhere in the text. Mr. Habashi: Yes, certainly, when we work out any partnerships, we will make sure that the marketer can approach our market if they wish to do so after we give up on it, if we choose ~to do that. So we will be very careful with any~ contract that we work out with any of those partnerships or marketers. Commissioner Sahagian: From my perspective, articulating that aspect in here as part of the third party strategy is important. My last point is in regard to the bottom of Page 2. I did not completely understand the last paragraph~ especially the last sentence. "...staff believes that utilities that enter the .competitive market on January 1,1998 will preempt competitors and would be able to hold on or acquiring market share." I do not understand what the logic was in that statement. Could you clarify that? That completes my cou~ents on the text. Other than that, I think it is very good.. Well done. Mr. Habashi: The idea here is that if we wait too lon~, if we wait until the.year 2000, for example, in order to open our doors, we may probably learn from what happened in the market place, and we may be experts by then, but we may be experts in acquiring in a market that had already been sold to the marketers who had already been out.there since 1998, working deals. What this sentence is saying is that if we enter the competitive market place at the same time that our competitors will, we believe that the likelihood is greater that we will be able to hold onto our market share, and perhaps even increase it. I agree with you MINUTES UAC: 12/04/96 FINAL PAGE 47 that the sentence is not very clear and should have been rewritten. Commissioner Gruen: I have two comments. The first one I would like to make in the form of a motion. MOTION: I move that instead of July i, 2002, we go to January I, 2002. The reason for that is that I think there is a perception which we have to address, and I would like the perception that Palo Alto gives you as many .choices as PG&E does. Mr. Habashi: If the Commission decided to go that route, I would suggest making it December 31, 2001,. which is the date that SECOND: By Chairman Johnston. I feel that that ought to be our goal. We talked earlier about how we may have some contingency plans and that we can make different choices later, but setting ourselves up with a goal that matches the other timetable I feel is a good goal. I would support that. Mr. Habashi: I would like to ask for clarification. The date of June 30, 2002 appears in two places, one in customer Choice and the other in stranded asset collection. Are you suggesting that the date would change in both areas, or in one or the other? Chairman Johnston: I did not make the motion, but I would think that it would be both. Commissioner Gruen: I would iike to see it in both places. Mr. Baldschun: That will, of course, change the timetable of therate plan that we talked about earlier today to some extent, but it may become moot next year when we update everything anyway. Commissioner Gruen: I did not have the feeling that you had precision in 2001 as to what we were going to do. We did make the same kind of suggestion when we were discussing the ’stranded costs. So yes, my intent was to do both of them. Chairman Johnston: I think the message here is that if we are making the decision that we are going to go competitive, and that we are going to open our doors and do all of those things for exactly the reason, Tom, that you just made about not wanting to delay, not wanting to stay ~out of things, you made it more in reference to the 1998 date with regard to the larger customers. But the philosophy really follows through on everything. I feel it is a good goal. We will always have MINUTES UAC: 12/04/96 FINAL PAGE 48 the opportunity to extend the CTC if we need to. But as a policy, think we ought to try and do it in that timeframe. Chairman Johnston: The motion is open for discussion. Commissioner Sahagian: I would like to suggest that maybe we expand the motion to include a non-bypassable competitive transition charge if we are going to make specific changes. Also a provision to make it clear that~any third-party arrangements that we enter into for power marketing would contain adequate non-competition provisions. ~ Commissioner Gruen: I would be happy to add those provisions if that makes life simpler for the parliamentary folks. The other point I wanted to make is that I feel the three things which we have talked about here are good things to do, and I would like to see a fourth point. The fourth thing I would like to be able to offer in the same spirit is that we ask our customers what they want, and we undertake a program to provide what they tell us they want, not just what they want, but if they are willing to pay for.it. The sorts of things I had in mind were some large industrial customer who wants to be fed from a separate substation, feeling that that would increase their reliability, and they offer to pay the cost of such a thing.. I would like to actively pursue doing that sort of thing, not just allowing it if someone beats on our door, but.going to our customers and saying, what is it that would make life better for you? What would you like, and then think about what we could do to offer that to them. tried to get this from the City of Santa Clara, and first of all, don’t think they understood the request. They didn’t believe we had a reliability problem~ After all, we were only out for a few seconds, which kept our computers down for three days. Secondly, they were unwilling to offer it.. They said, we are the utility, and we don’t have to offer the things you want. I think that increasingly, we are going to find ourselves with customers who, if they don’t get it from us, will get it from someone else. So as another element of the brave new world of electric utilities and utilities in general, I would like to proactively ask our customers aboutthings which would make them happier, and proactively offer them at a profit. We would do this for money, but we would not just say, we don’t do anything like that. Mr. Mrizek: Commissioner Gruen, I believe we are already doing that. We have doing that for a number of years. Our rules and regulations very specific where we have entered into a number of contracts and MINUTES UAC:12/04/96 FINAL PAGE 49 agreements, specifically with major customers in the Stanford Industrial Park. They may need a special power supply or a separate feeder completely separate for testing, or a loop feed, so if we did lose a feed from one substation, we would loop them from another. We have all of these types of agreements. Our engineering operations staff works consistently with them. Currently, we have a contract with Varian and Associates. We put in an additional substation transformer because they had very specific needs for short-term but very high-capacity testing of their high voltage tubes. That would certainly have created problems for all of our customersin the industrial park, so we put them on a separate transformer, a separate feeder. We told them that they would have to buy the equipment. They did, and we said that if they use so much energy per year, we would refund to them a certain amount of their up-front cost, and if they did use adequate energy each year, I believe it was within five years, ~hey would have all of their money back in their pocket. So we are already doing as you mentioned. When we had the outages last summer, we have been talking since then specifically with a number of customers on higher speed relays so that computers are not going to be down. So I am not certain that we need this as another policy statement when talking about deregulation. Commissioner Gruen: I am pleased that you are doing all of those things. I am suggesting two things that you may already be doing~ One is that there be a proactive approach, which says that you ask people, rather than w~iting for them to ask you. The second thing is that there might be systemwide things that you might consider, if there were another customer altogether... Forexample, multiple feeds to the City of Palo Alto, not just three lines in parallel, but lines from other places, ~that kind of thing. Mr. Habashi: I want to reiterate what Ed Mrizek said, which is that ¯ these things are already being done..What we are doing now is way above what we used to do in the past, given what we know about the marketplace. Another thing that I need to mentionhere is that the policy statements that we have here are changing the way that we do business atthis point. Right now, we do not have customer choice. We do not offer services outside of our service territory, and we do not have anything called CTC. These things are not there right now, and we need to put them in place. That is why we.are making the policy recommendations that we are making today.~ All of the things you have mentioned are definitely things that are very important for our competitive position in the future. However, they are not new. They are things that we have been doing, are doing now, and will be doing a lot more of in the future. MINUTES UAC:12/04/96 FINAL PAGE 50 Commissioner Eyerly: Richard, ~I think your thoughts are good, but we had a report about six months ago on the marketing plan and what .it was doing and. I forget who was the head of that department, but they are acting. Why don’t we ask for a report later this year instead of putting this in as a policy, so that we know what marketing is doing. Then, if we do not feel comfortable with what they tell us, we do not have to have all of these policies go in in one night. We can certainly develop another policy if we feel there is a need. But I frankly think they were moving along a little before you joined us, and they are telling you tonight that they are pretty busy on it. I think we could ask for a report every six months or so on something like that. Commissioner Gruen: I am certainly willing to hear what the marketing program is, and what it is before we talk about how to do it. June Fleming: I have come forward to reinforce what staff has already said. These are policies, general policy directions on which we really would appreciate having your ~support as we take them to the City Council. I think the issue that Commissioner Gruen has raised is one that staff has said they are doing and are conscious of it. It really addresses more what Commissioner Eyerly is addressing, that is, a market strategy. It may be something that you want us to do differently, and it may be something on which you want us to place more emphasis. I do not feel that it is a new policy. It is a policy that is in place, and we pay attention to it. You may want to look at it, and you maywant to have us emphasize something differently, but it is not a new policy. Chairman Johnston: Thank you. I have a question about Policy #3, Strategic Retail Market+ing. I want to make sure that we are all clear as to what we are talking about here. I believe the way it is worded is that the utility is.going to explore opportunities. As I understand it, this is not a specific commitment to actually sell power. It is a commitment to go out and evaluate the marketplace and figure out what we ishould be doing beyond our territory. Is that correct? Or is it more than that? mr. Mrizek: That is correct, and is alittle more than that, too. This follows along the guidelines on .which we ~ave been working with NCPA over the last~year since the last strategic planning session that NCPA held last January. The utility directors have been meeting with NCPA staff to look at what things we can do to basically make a profit. We have recommended breaking into four business units. That is being undertaken at this time. We also encouraged NCPA to explore partnering or forming strategic alliances with marketers that would provide cost savings to NCPA, and therefore, to the members of NCPA. NCPA has done that, and in fact, I spent the last three days in San Francisco MINUTES UAC: 12/04/96 FINAL PAGE 51 interviewing potential partners for NCPA, major marketers in the west coast. One of the things that these marketers will probably be doing is lookingat providing service to certain entities out.side of the NCPA service territory. Suppose there is a school district, one where we have open access, that wants to put out a bid. What kind of supply would somebody offer? Potentially, NCPA, along with this marketer, could make a bid on that. Those packages are being put together right now by a number of entities, and we want to be proactive in exploring and bidding on any of those that we feel can benefit Palo Alto and other NCPA members. That is what we are planning to do. Chairman Johnston: Some of the concerns I have are partly the same idea that I believe Commissioner Sahagian talked ~about, how your partners may, in fact, be your competitors. Also, it seems as though we are doing this, in a sense, at low levels~ On the one hand, Palo Alto is going to be out there lookin~ at alliances we can-create to sell power. At the same time, we are a member of the Northern California Power Agency, and we are supportive of of their essentially doing the same thing. So I am wondering if we are supporting two separate marketing efforts potentially going off to the same customers. Mr. Mrizek: No, we are not. Certainly, if through NCPA we did find some potential marketer who signs an alliance on the dotted line with NCPA, we would use that instrument to explore serving outside the City limits first. Maybe that partnership may not be interested in certain areas, and maybe we want to explore other areas on our own. There is potential for both -- going out and getting a marketer on our own to explore providing service to other entities where perhaps, the NCPA partnership was not interested in. It is not a panacea that NCPA is going to go out and make an agreement with a partner and we would make offers or deals just through that entity. Wewill explore both. Chairman Johnston: So in terms of this Policy #3, assuming the City Council adopts this policy,, does that mean that you would no~ need any more guidelines or any more policy statements from council in order to actually go out and potentially sign up some customer? Obviously, the City Council has to approve the contract. I understand that, but essentially, you would then have what you need in place in order to not justexplore these opportunities but to get contracts in place to be approved by the City Council. That is what we are talking about. We are not talking about something here that says, we are going to explore¯ a number of areas, and we are going to look at that, and we are going to come forward with some kind of a business planning process on what regions we are going to go after, anything like that. Mr Mrizek: No, we are not. Perhaps "...explore opportunities as MINUTES UAC:12/04/96 FINAL ¯PAGE 52 appropriate to enhance..." might be fitting to add. Mr. Habashi: If I might add, it is not likely that they will be starting tomorrow, going out and targeting customers. We have a period of somewhere .between six to nine months to put together an implementation plan. If you look at the staff report, the next steps say that in the next few months, we will be coming to you with an implementation plan. In that implementation plan, we will outline some steps that we will take to address just what you are talking about. Mr. Mrizek: I would also like to add that at the end of today’s interview session,-NCPA’s Mike McDonnell indicated that the next strategic planning session of NCPA will probably be held next February. The dates have not been established yet, but at that time, if a marketer has been selected, that marketer would be coming to that meeting to discuss+what they will be recommendlng to do with NCPA, providing not only the NCPA Commissioners an opportunity to hear from the marketer, but also for anyone else from Palo Alto who~attends this meeting to listen first hand to what NCPA has in mind for this particular marketer. Chairman Johnston: So this isreally a very wide open policy. Mr. Mrizek: Yes, it is very broad. Chairman Johnston: This will allow you to sign up Diesel engines~in Costa Rica. It is pretty broad. This starts getting into a difficult area, because we are going to start competing, and there is a problem as to what you can tell us at apublic meeting. What concerns me here a little bit is that we are approving something that is so broad, and we are doing it without really a plan as to what resources we are going to spend and what is a measure of success in that, things like that. It is fine. It is in a preliminary stage, and maybe that is all right, but it just seems very wide open. The other one seemed rather more specific. But I.guess that is what you need right now. Mr, Mrizek: That is all we need to start exploring these opportunities. That is all that we are asking for. Chairman Johnston: Okay. I think I am reasonably comfortable with ¯ that, depending upon what opportunities come back! Can someone craft a motion that incorporates all of the amendments that we have discussed? We have a motion on the floor to change the date from July I, 2002 back to January I, 2002. MOTION: Commissioner Saha~n: I move that we approve the staff MINUTES UAC: 12/04/96 FINAL PAGE 53 recommendation, with the following changes: that the date July i, 2002 be revised to December 31, 2001; that is in two places, under Policy Statements i and 2; also, that it be clearly stated in Policy Statement #2 that the competitive transition charge is a non-bypassable competitive transition charge; that under Policy Statement #3, the use of partnership or strategic alliances with power marketers contain adequate non-compete~ provisions; that we keep the wording "Palo Alto will explore opportunities to enhance..." as it stands. I move the staff recommendations on the basis that those changes be made. SECOND: . By Commissioner Eyerly. MOTION PASSES: ~Chairman Johnston: That motion passes unanimously on a vote of 4-0 withCommissioner Chandler absent. Item 9. ~ports of Offlcials/Liaisons ¯ b. TANb~ort.~ Doug Boccignone: \’,~,~,~am present for your L . --- Commisszoner Eyerly:’\.~n the last item, t] COTP report, I do not understand exactly whi’t,,,~ are talking a ~ . Ha~ PG&E accepted the transfer of South San Jo~,.q~n Irrigation I~ ~ L t"s 33 megawatts to the California Oregon Transmi~si~ Proj ~/~J .-. Mr. Bocciqnone: What happened ~PG&N actually f~nanced tNe South San Joaquin Irrigation District’s of the project. The irrigation district realized that they had expensive alternatives, and they had a provision in.their allowed them to turn it back to PG&E. They did so,. and we haw ..ing for legal reasons that they are a participant in the are a participant, a big "Big P" means that in It has been is a lawsuit going on Commissioner California-Oregon studying mitigati capability from there? ~ct, and it is very clear that they ~ant They actually own a share. ~ontract, parti were a defined term. PG&E has been a bl P participant, but there over that issue. I have one question the first item, the :ertie (COI). It says t working groups are measures to increase th~ allowable transfer to 4,800 megawatts. What do you mean Mr. ~ Following the outages on July capability ’~fc£r the COI is three lines, not just project, but the Pacific AC intertie, as it used to be the transfer is 4,8oo MINUTES UAC: 12/04/96 FINAL PAGE 54 MEMORANDUM TO: FROM: AGENDA DATE: SUBJECT: Utilities Advisory Commission Utilities Department January.8, 1997 Stranded Cost Strategy REOUEST This report is informational only. ,At the last two UAC meetings, staff updated stranded cost estimates under a range of assumptions, presented five year rate plans to fund the.Calaveras Reserve, and evaluated a number of mitigation measures to recover stranded costs. Also, during these meetings, the UAC provided comments and advice on a number of key issues. As a result of this process, the staff has developed a specific stranded cost strategy which is presented in this report. ~ RECOMMENDATION There are no recommendations and no UAC action is required. Staff will present the recommendation on this stranded cost strategy for UAC action during the FY1997-98 budget process. POLICY IMPLICATIONS This report requests no action at this time and therefore has no policy implications. Staff will. present the recommendation on this stranded cost strategy and policy implications for UAC action during the FY1997-98 budget process. ~- EXECUTIVE SUMMARY The centerpiece of Palo Alto’s strategy to recover .potential stranded investment costs.is to accelerate funding of the Calaveras Reserve during the transition period to full competition. Three key variables to this strategy are: 1) the, appropriate estimate of stranded costs; 2) the timeframe for the transition.period to full competition; and 3) the funding plan. The past two months, staff and the UAC have evaluated these variables in the context of how each variable or scenario would help position the Electric Utility in a competitive environment, balanced with the need to raise rates in a prudent manner.. Based on this analysis, staffplans to recommend a specific stranded cost strategy to assure long- range price competitiveness for Palo Altans as follows: something like that, which to me is a very real possibility, .and perhaps have a good outcome, if we can, at the same time, get a somewhat more reliable water supply. ~ommissioner E~eL~: I need a staff report on those types of things so that we have it down on paper to look at it and so that others can see it. Commissioner Gruen: I would also like to see some measure of water quality, as well as water price, just as we have been talking about the water quality from the various supplies available from the City of San Francisco. I would want to hear about the water quality available from the Santa Clara Valley Water District or whomever else you were considering. If TDS is not the right thing, then tell us what is the right thing to look at or how do we measure quality. I think quality is a very important issue. The number of people that I see using bottled water have voted with their dollars for.waterquality. I think we ought to ’take some cognizance of that. ~~~_Q~: Thank you all very much~ This has been extremely helpful. I anticipate that you might be prepared to come back to us at the appropriate time. I cannot say whether that is one year, two years, five years, but it sounds like there is a lot of activity going on, and much of it will crystallize over the next few years. I appreciate your taking the time to come down and talk tO us. Absolutely. ~: I~have just a few prepared remarks. This is our third meeting~on the subject. This year, we.have reviewed this subject rather extensively, as you know. We have gone through a rather exhaustive process of trying to identify all of the issues and what our options are and what the risks are. In this report that you havebefore you tonight is our planned recommendation which will be coming back to you for action during the budget process .this spring for fiscal year 1997-98. The proposal is to use the low market price forecast, which rec~nt estimates would generate a stranded cost estimate of approximately $93 million. That is the estimate "that we are satisfied with at this time. Regarding the issue of a transition period, we are recommending a transition period that coincides with the investor-owned utilities transition period.For us, that will begin July I, 1%97 and December 31, 2001. P~ge ~ The last issue in the recommendation is how we fund the stranded cost in terms of building up the reserve. Our recommendation is to use consecutive rate increases, single digit, and use the savings we are currently experiencing in our power costs and other operating budget savings to build up the reserve. Commissioner Gruen: Randy, I did not get the sense from this that you had a plan for how frequently you would review what we were doing on establishing the reserve, how much we had, whether we were Qn track, whether the low-low estimate, or the high-low estimate, or the medium estimate was appropriate. What is your plan along those lines? Mr. Baldschun: The policy that the Council approved is essentially that we will update the stranded cost estimate on an annual basis. Unfortunately for us, we are going~to have to come back probably in the fall of every year during the transition period and revisit the market price forecast and revisit the estimate and revisit the final plan. As you know, it has changed quite a bit just during the last two sessions we have had with you, so next year, we will be doing it again to.update it. C_o~m~issioner Gruen: ~That sounds good to me. Mr. Johnston: I am quite happy with what you have proposed here. Consistent with your most recent response you had to the last question, the cost estimate being based on the low market price scenario is what we are proposing to use as of now, but anytime in the future, we might make an estimate obviously that~ could or most likely would change one way or another. I take it that we are not saying we are going to go with that for the duration. We are saying that is the current best estimate, and we .are going to use that for now. I support that. I am also happy with reaching the target six months earlier, as we have talked about before. I would support your third recommendation here in terms of dealing withthis by single digit rate increases. My only hope, with regard to that, is that while I agree we should keep it to single digit, you do get more recovery for a rate increase this year versus one next year. I think that should be kept in mind in terms of keeping the most flexibility for the future. We should keep it at singie digit, but I would like to see that we look at trying to capture as much~as we can in this first go-round. I am supportive of this, and I guess we will hear from you again when you come back. ~: I have a little question. When you say single digit, does that mean nine is the largest number, or that 9.% is the largest number? MINUTES UAC,’OI07~/Final P~e 2~ MEMORANDUM TO:Utilities Advisor)’ Commission FROM: AGENDA DATE: SUBJECT: Utilities Department December 4, 1996 Rate Plans to Fund Stranded Costs REQUEST This report is informational only. At last month’s UAC meeting, staff updated stranded cost estimates arising from the .Calaveras Hydroelectric Project and the California Oregon Transmission Project (COTP). This report presents five year rate plans to fund the Calaveras Reserve for two stranded cost estimates. It also outlines possible mitigation measures to recover stranded costs during the transition period and after full competition begins in 2002. RECOMMENDATION There are no recommendations and no UAC action is required. .POLICY RECOMMENDATIONS No policy recommendations are contained in this report. However, in order to calculate stranded costs, some policy decision assumptions have been identified. Key assumptions include providing Palo Alto customers a choice to select suppliers and instituting a Competition Transition Charge. This technical review and evaluation of stranded costs with the UAC may lead to policy implications and subsequent actions by the Council. EXECUTIVE SUMMARY The centerpiece of Palo Alto’s strategy to r.ecover potential stranded investment costs is to accelerate funding of the Calaveras Reserve during the transition period to full competition. The five year transition period begins 7-1-97 and ends 7-1-02. Staff evaluated alternative financial strategies to fund the Calaveras Reserve during the transition period for two stranded cost estimates being considered. In Case 1, additional funding of $20 million would be required based on a "medium-10w" market price forecast to calculate stranded costs. Case 1 indicates a 7% rate increase in FY97-98 to raise the Calaveras Reserve to a target level of $62.4 million in FY2001-02. Case 2 represents a low-market price scenario and indicates that additional funding of $51 million is required to raise the Calaveras Reserve to a target level of $93.1 million. This suggests rate increases of 8% and 5% in the .next two consecutive years. To soften the rate impacts.during the transition period, a number of mitigation measures are identified for consideration. Also, a number of mitigation measures available after the transition period are identified. These actions could generate additional revenue or cost savings at a time when raising rates may not be a viable alternative. While some mitigation measures may be taken for sound business reasons, others may be taken only if stranded costs are higher than accommodated in the Calaveras Reserve. Last moath a total of six stranded cost estimates were presented to the UAC based on different market price scenarios and assumptions. For this month’s rate analysis, two market price scenarios have been selected to calculate stranded costs’ for the period 7-1-02 to 7-1-24. The stranded costs shown in Table 1 differ from the estimates provided last month, due to a presentation format based on an end of fiscal year basis i.nstead of a calendar year basis and correction of an error in the. medium-low market price calculation. Because of the uncertainty with forecasting, stranded cost estimates will be updated on an annual basis.. Next year, events could bd settled regarding the COTP and there is a possibility, that the stranded cost of this transmission project will be reduced significantly. Other factors will tend to increase or decrease current estimates. , The Calaveras Reserve target is based on potential stranded costs arising from the City’s participation in two projects. In Table 1, a breakdown between the two ’projects allows a comparison of the percentage of the Calaveras debt service obligation represented in the Reserve. For example, under Case.2 the Reserve would cover 73 % of the debt service obligation between FY02-03 and FY23-24. In nominal dollars, the amount is $79 million for Case 1 and $144 million for Case 2. The Reserve would pay this level of the Calaveras debt service in addition to accommodating potential stranded costs of the COTP. This information conveys to what extent the Calaveras Reserve would cover the high fixed cost (principal and interest payments) Of the Calaveras Project. Project Calaveras COTP Tom] TABLE ONE Case l:Mediura-Low Market Price Stranded Cost % CaIaveras Debt Service 20025 Millions $47.1/40% 15.3 $62.4 Case 2: Low Market Price Stranded Cost % Calaveras Debt Service 20025 Millions $77.81 73 % 15.3 $93.1 2 During the transition period (7-1,97 to 7-1-02), a Competition Transition Charge (CTC) Will recover stranded costs incurred. In addition the CTC will collect potential stranded costs projected for the period 7-1-02 to 2024. During the transition period, the CTC will be revised on an annual basis to incorporate updated stranded cost estimates. To achieve the Calaveras Reserve target, the current financial strategy is to continue building up the Reserve through favorable power cost variances in combination with a rate increase(s) (CTC) to generate additiona! revenue. The current Calaveras Reserve balance projected this fiscal year is $42 million. Table Two presents a 5 year rate plan to achieve the Calaveras Reserve targets for Case 1 and Case 2. To meet these targets requires additional funding through FY01-02 of approximately $20 million and $51 million under Case 1 and Case 2 respectively. The rate projections in Table 2 may change during the budget process as reserve, revenue, and expense data are updated. TABLE TWO Case 1: Medium-low Market % Rate Adjustment Case 2: Low Market FY % Rate Adjustment 97-98 8% 98-99 5 99-0O [0 00-01 0 01-02 0 02-03 -12 7% 0 0 0 0 -4 MITIGATION MEASURES DURING THE TRANSITION PERIOD The multi-year rate plans identified in Table Two allow the Utility to build up the Calaveras Reserve to meet certain targets. The rate projections incorporate revised power costs due to favorable market conditions and an anticipated NCPA refinancing of the Calaveras Debt to reduce costs. However, if appropriate, there are other funding and cost minimization alternatives (A through D) that could also buildup the reserve and thereby soften rate impacts during the transition period to full competition. The following steps, if taken, would lower the Utility’s overall revenue requirement in the near term. As a result, the component of the retail rate previously funding this activity would become available to fund the. Calaveras Reserve. A. Defer Capital Improvement Projects The CIP budget is funded from current rates. Deferring certain CIP projects withoflt affecting reliability of service would reduce the revenue requirement in two ways. First, the cost of the project is eliminated in that year. Secondly, in actor.dance with the Utility Enterprise Methodology, the Transfer to the General Fund is lower than otherwise would be the case. It is estimated that approximately $8 million-S11 million could be saved during the transition period by deferring certain CIP p’rojects. B. Bond Finance the CIP Long-term debt financing provides an infusion of cash to the Utility. Bond financing the CIP is an important tool to ease financial problems in the near term since the financial obligation is spread to subsequent periods which more evenly matches the useful life of the distribution assets. As an example, Palo Alto could issue long-term bonds to finance annual CIP activity of $5 million. The issue could cover a future three year period, thereby adding approximately $15 million to the Calaveras Reserve from bond proceeds. Assuming a 6 percent interest rate on 25 year bonds, a $15 million bond issuance translates to an annual debt service payment of approximately $1,200,000. It is also assumed that at the conclusion of the three year period., the annual $5 million CIP would be funded by’rates. However, in addition to funding the annual CIP of $5 million, rates would also have to cover the debt service payment of $1.2 million for the next 22 years. Because of this added, revenue requirement, long-term debt financing raises rates higher than pay as you go financing. $1.2 million represents a 2 percent increase in current retail rates, However, $1.2 million applied to a "distribution rate" (that is planned to be unbundled from generation) represents approximately a 6.3 percent rate increase. In this example, financing a 3 year $15 million CIP raises rate levels for 22 years approximately 6.3% higher than .would result from a "pay as you go" financial strategy. This could be an issue. The recent organizational review, by Theodore Barry & Associates encouraged the Utility to strengthen efforts at distribution cost containment. C. Freeze or Lower Operating Costs Since FY92-93, the Electric Utility has .reduced its operating budget, exclusive of p~rchase power costs, approximately $3.5 million or 12 percent. To the extent additional cost reductions are identified, such savings can be transferred to the Calaveras Reserve. The recent organizational review contained recommendations on this matter which will be evaluated during this fiscal year. The Gas, Electric and Water Funds all provide equity transfers to the General Fund. In the Electric Fund, the 1997-98 transfer is projected at $7.5 million, which represents approximately 11 percent of the 1997-98 preliminary. Electric Fund expenditures. The UAC has raised the issue of the appropriateness of the Utility Enterprise Methodology which applies a rate of return to the value of depreciated utility assets to arrive at a transfer amount. The concern of the UAC and the staff centers around the impact of the aggressive infrastructure replacement program and its impact on the transfer calculation. Accordingly, staff committed to a comprehensive review of the transfer methodology with the 1998-2000 budget cycle. This will also provide an opportunity to examine other issues in conjunction a transfer methodology. Such issues include the appropriate ratemaking methodology to use in a competitive environment and the appropriate disposition of excess revenue or costs that may occur as prices (reveaues) are driven by the market rather than by the utility’s cost of service. D. Unbundle the Rate Stabilization Reserve In 1993 Council established the Utility Rate Stabilization Reserve (RSR). The RSR combinezl the Transfer Stabilization Reserve and System Improvement Resen’e a~d developed reserve guidelines based on 12 power cost contingencies. The RSR serves to accommodate operating and capital budget variances as well as power cost variances. In view of the plan to establish separate rates for commodity and distribution services in FY97-98, a similar need will arise to introduce an RSR for commodity as well as an RSR for the distribution system. Depending on the new RSR guidelines to be developed, a fund surplus may be identifi~ as a result of the unbundling which could flow to the Calaveras Reserve. If one or more of the aforementioned mitigation measures are implemented in combination with a rate adjustment, the magnitude of the rate increase would decline. The chart below represents an alternative financial, strategy to build up the Calaveras Reserve by $51 million during the transition period under a Case :2 scenario. This funding strategy reflects an 8% rate increase, deferring a $2 million CIP for five years, achieving operating cost savings of $600,000 per year, interest income of $5.8 million and lower debt service due to Calaveras refinancing. Case 2: Calaveras Reserve Target = S93 Million Sources of Funding O & M Savings l~~ $ 3MM Rate lncr.IOtherCalavcra.s Balance ( i ~Additional Funding $ 38MM I ~! ~ i!l~.,~D~.fer CIP ..... -----$ 10MM MITIGATION M-EASUILFS AFTER THE TRANSITION PERIOD (FY01-02) The adequacy of the Calaveras Reserve to recover stranded costs will depend on the proven accuracy of the market price forecast of electricity. Given that the 27 year forecast will prove either, high or low, it is useful to consider the downside and upside risks in deciding what constitutes a reasonable amount to set aside in the Calaveras Reserve by 6/30/02. With that objective in mind, a list of potential mitigation measures available after the transition period are identified to help put the level of risk in perspective. [] IF STR:.dNDED COSTS ARE LOWER THAN FUNDED IN RESERVE If funds are overcollected there could be customer complaint issues. The primary options to : reduce the surplus include application of a customer rebate or alternatively lowering’ the commodity cost to existing customers. However, from an administrative standpoint, it could be difficult to locate or determine what level of credit a customer may be entitled to who has alternated between Paio Alto as-a supplier or who has moved from the area. From an equity standpoint, former customers who paid into the Calaveras Reserve between 1997-98 and 2001-02 could claim a right to a refund. ~1 IF STRANDED COSTS ARE HIGHER THAN FUNDED IN RESERVE A decision to raise rates after 6-30-02 will have to be balanced against the adverse effects such an action could have in a competitive environment. The following mitigation measures address a condition if the. Utility finds itself in a position whereby the Calaveras Reserve is inadequate to recover stranded costs and raising rates is not considered a viable remedy. The measures vary in merit, political feasibility, and probability of success. The favorable financial impact of some of these measures was not included in the long-term financial analysis that was used to estimate stranded costs, even though some measures (B,C,E) would likely be implemented regardless of the need to mitigate,stranded costs. A., Application of a CTC After FY01-02 AB1890. specifically allows municipally-owned utilitys to charge a CTC indefinitely. While this mitigation measure reduces the financial exposure of the Electric Utility to stranded costs, there are political and customer relation considerations with this measure. Some municipal utilitys may be planning to extend a CTC to 2003, 2005, or later. However, industrial customers of investor-owned utilities will,cease to pay a CTC after 12-31-01. Residents and small commercial customers of investor-owned utilities will pay a CTC until the rate reduction bonds are paid off. Accordingly, it may be unpopular to .charge a CTC in Palo Alto if it is effective at a time when similar customers in surrounding areas are no longer paying a CTC. Nonetheless, a CTC is a "parachute" available to the City. B.. Restructure or Refinance Calaveras Debt The current Calaveras debt service schedule terminates in 2024. To the extent that NCPA restructures debt by extending the final maturity date to 2032, or converts some of the bonds into short-term variable interest rate debt, stranded costs may decline for two reasons. First, the revised debt service schedule would probably lower annual payments.. Secondly, the probability of entering the period of stranded benefits before debt is paid off increases as the schedule lengthens in time. NCPA is currently planning to refinance and restructure debt of the Calaveras Project. Should other.refinancing opportunities arise in the future, stranded costs would be lowered further. C. Market Off-sTstem Sales to Increase Revenue Contingent upon Council’s approval, staff plans to leverage its resources and market power beyond Palo Alto’s borders. To the extent the Utility is successful in this activity, incremental revenue would be earned that could help mitigate stranded costs. D.Shift Costs to Distribution 6 Merrill Lynch has suggested this strategy as an option for municipal utilities to consider. This approach is applicable to municipal utilities with little or no outstanding debt on their distribution system assets. Merrill Lynch states that participants (municipal utilities) "may be able to refinance Hydro debt with contracts that are related to their Distribution system assets. In effect, they can strip cash out of the equity in their distribution assets and use it to retire the hydro debt. This will shift costs to Distribution where they are non-bypassable. Participants can.also consider imputing a return on equity to their Distribution system assets when setting rates to shift costs to.non-bypassable assets.. Unfortunately, this cost-shifting strategy does not produce inherent economic benefits in the sense that total revenue requirements are not effected." This approach may help to’ recover stranded costs but it could create new problems. It is assumed that under retail wheeling, rates will become fully unbundled between commodity, distribution, and transmission. As customers and marketersbecome more sophisticated, it is likely that questionable ratemaking practices will draw complaints. To the extent supply related costs are added to a distribution,charge, a legal challenge may arise on the basis that such cost allocations are inappropriate and violate sound ratemaldng principles. In effect, customers would be paying the current commodity rate for supply and also pay a portion of their non- "bypassable distribution charge that is attributable to refifiancing of stranded generation assets.This could occur well beyond the standard CTC transition period. ending in 2002. Despite deviating from traditional ratemaking principles of cost allocation, this strategy is being openly considered by investor-owned and municipally-owned utilities. Another concern with thi.~ strategy is. that it increases the distribution charge which must be balanced with other considerations. Specifically, a non-competitive distribution rate may build momentum to: 1) generate customer dissatisfaction, 2) add political pressure, 3) contribute to self-generation, and 4) create total bypass circumstances in the service territory. E....Telecommunications RevenueThis year the City Council approved the UAC recommendation for the Electric Utility to develop a fiber optic ring around Palo Alto by leveraging existing Electric Utility infrastructure. "The risk would be borne by the Elb.ctric Utility with the belief that the risk is limited and that the recommended strategy will diversify the Electric Utility’s revenue streams into a growth market and better position the Electric .Utility for impending competition in the electric utility industry (CMR:361:96)." Current expectations are that this business will produce net revenue in 4 to.5 years and continue thereafter. Such revenue could help to lower overall electric distribution.charges to Palo Alto ratepayers. It is assumed that telecommunications revenue would not directly offset stranded costs since it is not related to the generation side of the Utility business. However, it is included here because it’may indirectly help recover stranded costs. To the extent such activities result in lowering the distribution rate below competitive levels, strategies such as described by Merrill Lynch above may have more appeal if stranded costs were higher than accommodated in the Calaveras Reserve. .CONCLUSION Stranded cost estimates pre.sently under consideration range from $62.4 million to $93.4 million in 2002. To fund the Calaveras Reserve to accommodate such levels could require rate increases over a five year period. While there are mitigation measures the Utiiity may take to soften such rate adjustments, the magnitude of the rate adjustments suggests that only moderate measures nee_A be considered. Stranded cost estimates rely on highly speculative forecasts of market prices for the next 28 years. In reality, the Calaveras Project may prove to be a strong economic asset for the Utility or it could turn out to be unmarketable. The forecast scenarios used in this recent analysis lean toward the latter case. During the next five years, there is a window available to provide for stranded costs with relatively moderate rate increases. This is particularly true if rate adjustments are used in conjunction with other mitigation measures to build up the Calaveras Reserve during the transition period. Under any scenario, there appear,to be mitigation measures to recover stranded costs to sustain the Utility’s financial viability beyond the transition period. AB1890 allows municipal utilities to collect a CTC indefinitely which, in effect, is a "fiscal parachute". Other financial tools such as debt restructuring or debt refinancing may make sense. Nonetheless, to the extent the worst case stranded cost estimate is accommodated in the Calaveras Reserve, the need to consider such’ mitigation measures in years following the transition period will be significantly diminished and long-range price reliability will be more assured for Palo Altans. Next month the staff will present its overall recommendation on stranded costs f6~: UAC input. Then, the final recommendation by the staff on this subject will be presented to the UAC during the Spring budget process. FISCAL IMPACT No recommendations are contained in this report and there is no fiscal impact. ENVIRONMENTAL ASSESSMENT This informational report does not constitute a project under the California Environmental Quality Act; therefore; an environmental assessment is not required. PREPARED BY: DEPARTMENT HEAD APPROVAL: CITY MANAGER APPROVAL: Randy Baldschun, Assistant E Manager of Utilities ~irman Johnston called the meeting to order at 7:30 >.m. cil Chambers, 250 Ha!hilton Avenue, Palo Alto, Cali~ ~a. Item Roll Cal! ABSENT: Commissioners Eyerly, Gruen, Chandler and Sahagian. in the COUNCIL ¯ PRESENT: None Item 2. Oral Item 3. Chaiz~nan Johnston: 6, 1996. is approval of the minutes.of November MOTION: executive summary of SECOND: By MOTION PASSES: Commissioner Saha, absent. I move approval of the minutes and 6, 1996. That passes on a vote of 4-0, with Item 4. would : I would like to request Report) to follow Item 6.b., ( ¯ ~n to be a logical location for it.. staff that we move Item Update) as that It 6. Unfinished Busines~ a. ~lans toFund Str nd . ~r. Bal~sch!l~: Said Good Evening. Tonightwe are going to go into Phase 2 of the three-meeting episode on stranded cost. Last month, we looked at a range of estimates based on various market scenarios. We noted some differences between ~the forecast that had been updated from the spring. Tonight, we have taken, two of. those forecasts, the low market price scenario; .as well as the medium-low market price scenario, and calculated what kind of rate impacts that might have if we were to fund the Calaveras Reserve to a level that would accommodate those estimated MINIYI’ES UAC:12/04/96 FINAL PAGE stranded costs within a transition period beginning July i, 1997 and ending July i, 2002. I do not have a lot of prepared remarks. We can open this up for questions and dialogue. Commissioner Gruen: Asked I have a couple of questions on this. We have a numberof reserves floating around in the utilities. One of them is the so-called ~rate stabilization reserve." What plans are included to transfer money from the rate stabilization reserve that reserve into the Calaveras Reserve? Mr, Baldschun: Answered There .are no definite plans, because it is too premature tonight to make a recommendation in .that regard. What we mention in the report is to put on notice that when we unbundle the retail rates, we also have to be unbundling our rate stabilization reserve between the transmission relatedactivities, generation-related activities and distribution-related activities. As a result of that process, we might possibly find a surplus that could go into the Calaveras Reserve, but that will be a whole separate study. Commissioner Gruen: In the council packet this week, there was an accounting of various reserves. Grossly, the numbers were that there was $33 million lying around in the rate stabilization reserve. If one did mere proportions of our expenses on distribution and transmission and generation, generation would get a large quantity of that. Am I missing something? Mr. Baldschun: I have not seen that. Are you referring to the semi- annual report? I just heard about it today, but I have not seen the numbers. One question I would have is,~ of the $33 million, does that include the $16 million transferred to the Calaveras Reserve that Was approved by the council? What I am saying is that it may not reflect that. ~ommissioner Green: That is really what I am trying to find out. These are year-end closing entries, as described in the council packet. ~/~: Effectively, that is the balance as of June 30th, but as of July I, it would effectively be transferred, I believe, or certainly during the next fiscal year, 1996-97. ~ommissioner Eyerl~: Said Randy, it looks like you dug into a lot o~ things, and I have several comments. I think it is very important that we pay off the stranded costs quickly on Calaveras. I see the Calaveras project as a very valuable asset. Does it look like it is going to 2032, and then we are on a very viable rate situation with Calaveras Water District after that at minimum cost? The only thing we have to MINUTES UAC:I2/~6. FINAL PAGE3 compare as to whether we should save that is market prices on energy. We do not know how long market prices are going to stay as they are now, and there is no way to tie it down. When you have a very valuable asset like Calaveras, I think we need to really get after the stranded costs and do that as rapidly as we can sensibly. What I find missing in ~here are rate comparisons. I know it is early to have it but .this Commission is going to need it in the next few meetings when we get down to rate setting. We are going to need to compare an increase in rates to take care of stranded costs and what it is going to do in competition with PG&E’s rates. I don’t know if you are going to be able to get them this year with all the changes going on in the electric utility. That is one thing I would like to see come along. Going through the repor~ and the mitigation measures, I have few comments about those. 0n Page 3, during the transition period, deferring capital improvement projects, I would not favor that unless we were in really dire straits and we could not come up with enough rates to take care of continued capital improvements as needed as we proceed ~through the transition. The bond financing, which Paul has brought up to us from your explanation on it, Randy,. seems like it would be more expensive, from what you are saying~ over the long haul. Paul may have some remarks about that, but it seems like that is not really a viable option, either. The freezing of operating costs or lower costs is what we have been working on for some time now. We certainly need to carry on on that. After the transition period, your concerns about whether stranded costs are lower than funded in the.~reserve, and what would we do with the excess money, I don’t believe Palo Alto would have any problem with that. We.have refunded it before, and although it might be a little bit of a problem to find out who was deserving of a refund in view of movement of customers, etc., I think that is really the only Simple way to do it. If stranded costs are higher than funded in the reserve, you have mentioned about whether we would want to be collecting any costs during the transition after the transition period, 2001~2002. I certainly do not think we would want to do that. Possible restructuring of the Calaveras debt makes good sense, and marketing off-system sales to increase revenue makes good sense. I have some problam with the suggestion that Merrill~Lynch has put forth on shifting costs to distribution, that in more detail before I could speak intelllgent~y to MINUTES UAC:12/04/96 F~NAL PAGE it. Those comments will give you my feelings as to where we ought to be going and what you ought to be coming.back to us with as we get towards suggestions ~for rates. ~r, Balds~hun: Those are very helpful, Fred. If each of the Commissioners could make similar kinds of comments in those areas, that would help us in coming back next month and formulating a recommendation that we would plan to bring back for final recommendation during the spring. Commissioner Saha~ian: Said for the most part, I would agree with the general direction of Commissioner Eyerly’s comments. I would avoid, at least at the onset, any additional encumbrances to deal with the buy- down of the debt, looking to rate increases to accomplish that, and use financing mechanisms as perhaps your contingency plan downstream if, in fact, competitive rates drqp below a conservative projection so that you needed to find other sources of capital to deal with further buy-doom and not look at it as something you want to integrate in at the onset. Personally, I would vote in favor of using the lowest projection for power rates to do your benchmarking off of, and-use the rate increase mechanism to deal with it as you have outlined in here. Then possibly the other comment was that you show, in your low case, a two- consecutive-year adjustment. I was wondering how you had arrived at two rate increases, versus possibly three something like that, to perhaps spread it out a little more, giving yourself the opportunity to go back and reanalyze where you were. I think that is a key part of the strategy. Mr. Baldschun: Answered far as the rate plan to have two consecutive rate adjustments, we always try to keep any rate adjustment in a .single digit, so that takes care of the first year. We looked at deferring the second rate adjustment another year. You lose, of course, the year you would have collected, and that ends up in a larger rate adjustment. It is a matter of judgment. What would happen, actually, is that we would look at the numbers that second year, and we would have new information, new numbers. This is just to give you an order of magnitude~ Ideally, we would not have to"have two consecutive rate increases. ’ .: I was not questioning having two increases. I was thinking of perhaps spreading it out over three years, but I appreciate your commentabout the capture of funds early on, because it pushes things toward the back end. ~: I will begin by trying to give you some feedback on some of the suggestions in here, and then I will have some questions about the calculation of the amount that we are trying to fund here. MINUTES UAC:12/04/96 FINAL PAGE 5 First of all, I think we should recognize that we are in a situation right now where we are extremely competitive and that we are looking to a more uncertain future where it is going to be more difficult to be competitive. Therefore, I support what has been said before up here that we need to take care of this now and that we ought to do it largely by a rate increase. To me, when you go through and look at the alternatives, I thought this report was very good, because it listed a big range of alternatives. I would reject most of the alternatives, but i think it was very valuable to have them laid out as it was done in this report. In evaluating the alternatives, one should decide whether th~ particular alternative will either make us more competitive in the future or less competitive beyond the2002 timeframe. Those techniques for finding the stranded costs that will make us less competitive in the future believe ought to be rejected in favor of policies that will make us more competitive in the future, therefore making us deal with it now. If you deal with that philosophy and you go through alternative mitigation measures, for example, capital improvement projects and deferring them, certainly we can always look at capital improvement progra~ns, and as time goes on~ reevaluate what is needed and what is not needed, but conceptually, we should not be deferring maintenance or deferring capital improvement projects, because that is going in precisely the wrong direction. That is making us less competitive in the future. If anything, we should be:bringing them forward, not.pushing them back. So I would suggest that that is generally anapproach that we ought not to follow. Bond financing for the electric utility in fact falls pretty much in the same category. It is basically saying that it is a way of deferring some costs, and what we really ought to be doing is paying the costs now when we are competitive and getting us cost-free in the future so that we can then be more competitive in the future. Absolutely and obviously, we are always.trying to do freeze or lower operating costs. It doesn’t much matter what situation we are in, that is good to do at anytime. Unbundling the rate stabilization reserve is certainly something that should be looked at. As you point out, it is going to be treated "differently in the future, and we should take an honest look at it and see what we need for the future ’with that. Maybe there is some money there, maybe there is not, but I feel that is reasonable to look at. When you go into contingency planning, it is good to have contingency plans, but I do not feel they should be looked upon as something we MINUTES UAC:12/04/96F/NAL PAGE 6 would be much in favor of having to get into. I really feel that to remain competitive, we ought to try and do everything in the same time frame that the investor-owned utilities are doing. Frankly, for me, that means that I would prefer to see it completed six months earlier than what you propose. If I understand the dates correctly, our proposal completion date of July i, 2002 was probably done because of budget years, but I feel that if you look at what the time periods are, you would be more likely to try and complete it by the end of 2001. So I think you ought to look at whether we may be six months too late there. If is fine to have that as a contingency, but I would be inclined to bring that time period forward by six months. On restructuring the Calaveras debt, that is probably the only point where Iwould disagree with Fred. The reason I feel we ought to be very cautious about doing that is because projects have a habit, after a substantial period of time,, of requiring substantial new investment for upgrades, improvements, etc. For us, it lo0ks nice if Calaveras, after 2024, will be debt-free, but I think we ought to think in terms that by 2024, there may be all kinds of other improvements or upgrades that may be needed. So again, I think that restructuring that debt ought to be perhaps a contingency, but definitely, a low priority. On the issue of marketing offosystem sales, I believe we are again going to try and~do that regardless, seeing where that will eventually take USo Shifting costs to the distribution system I feel is going to be really difficult to justify. It seems to me that you have a bunch of rate payers out there who, for the most part, have paid for the distribution system on a pay-as-you-go method. As we hav.e talked about before, on top of that, they. have paid 9-1/2% of the transfer each year to the general fund. Now, there is the suggestion, and I know it is only an alternative, that you might.go out and refinance it, asking the rate payers to pay for that again. That does not seem to me to be a very wise way to go. Again, it is an option in an emergency, perhaps, but not something I would advocate. So wher~ I come out when I look at all of this is very much the way I think.the other Commissioners have come out in essentially saying, there is. some medicine here we need to take and we need to take and deal ~with it right away. There are certainly some things in here to look at, but the lion’s share of it is probably going to come out of rate.increaSeSo I have one question about the low versus medium-low future cost scenario. It seems as though from the report we got the last t~me, Randy, that there were more supporting data for the low rather than for MINUTES ~JAC:I2104D6FINALPAGE 7 the meditun-low scenario, which seems somewhat consistent with the way this report is written. What I would suggest is that if we are getting to a point where the low future, cost scenario looks like it is our current best estimate, we ought always to have contingency planning in case it is more rosy than our-best estimate and also in case it is less rosy than our best estimate. So I am a little uncomfortable, if we are getting to the point where we think that the low market’ proj.ection might, in fact, be the right one, I am a little uncomfortable that the range of things we look at is only on the rosy side of that, i.e., the low-medium side, as opposed to saying that all.right, the low now looks like our best estimate, and it is time to reevaluate, therefore, the range we are looking at with the low being the best projection, and considering some that is more pessimistic than that and more optimistic than that. Do you have a comment on that? Mr. Baldschun: Said that i~ a wise thing to. consider. The evidence is actually mounting. We have gotten additional quotes from other sources confirming that the view of the market today, at least, is tending toward the low side. It is not going even lower, but there is always that possibility. ~hairman Johnston: Right,. and I would agree with that. From-what I have seen, most of which you have provided us, is that the current market projections tend to be pointing toward thelow, although they may be wrong, as’we recognize. Therefore,.for planning purposes, we really ought to look at a spread on that. We really ought to be looking at something above that, which" is perhaps a low-medium, although it could be refined, and we really ought to be looking at what you might perhaps call a new low, or a low-low. For planning purposes, it seems to me to be prudent to be looking at a range where your best protection is somewhere in the middle of the range, not at one end of the range. That is one observation ~ would make. A second comment has to do with the setup provisions with regardto the Calaveras debt. I would.like to see us evaluate that perhaps a little bit more. I do not quite know what could be done, and I suppose ideally, if I were looking at this, I would like to say, what would it cost to go out and buy an insurance policy to cover the setup provisions. If you could get an insurance policy, then the question is, would you actually buy the policy or do you go ahead and increase the capture of stranded costs, as representing the insurance policy being a best estimate of what those costs might be. Are we going to do anything about the setup provisions, or are we just going to hope it does not happen? Naturally, we hope it does not happen, but we are~having MINUTES UAC:12104/96 FINAL PAGE 8 discussions with NCPA. We know that the NCPA finance committee is looking at the possibility of refinancing the hydro debt near the end of either 1998 or 1999. We do not have any facts on it yet, but we are asking questions right now as to whether the setup provision is going to be changed. We really do not have that answer. You have a very good point there of perhaps doing some plan~ing in case that does happen and that additional debt falls on our shoulders. Mr, Habashi: I could offer a simple point here that if we are submitting stranded assets to be about $80 million, that is~almost two- thirds of the outstanding debt of Calaveras. That only leaves us with about $40 million. We plan to increase that further to prepare for a more pessimistic market prices. That probably be somewhat pushing it. There is a fine line that we have to.get to here. We need to make sure that we have sufficient resources and reserves to meet our stranded costs, taking into account, the lower market prices. We also do not want to reach a point where we have to force a very large rate increase that will turn our customers against us, causing them to depart the system when we open it in.1998. So that is the point I wanted to ~ake. Let’s be as prudent as we possibly can without going beyond a certain point where we end up losing our customers. Commissioner Gr~n: Said I would second most of the comments you have heard so far. In particular, I would agree with Chairman Johnston on accelerating the program so that we have paid off all of our competitive charges by the time everyone else is finished doing competitive charges. That is the point at which we will be competitively facing lower rates, and I think that we ought to put ourselves in the same position of being able to offer competitive lower rates without old baggage lying around. As far as I ~m concerned, if one of the ways to do that is to start the rate increase three months earlier, I could certainly go along with that also. There is nothing which says the budget cycle has to ~atch rate increases if we can .see a clear reason for wanting to do something different. I would concur that I would not like to see the Calaveras debt stretched out. Refinancing it at a lower interest rate certainly sounds like a cost-reduction mechanism. I want to distinguish that from somehow financing it with bonds, etc., so that we would have more baggage going into a competitive era. I think we have a shot now, while the other utilities in California are dealing with competitive charges, for .us to get our baggage out of the way. Then I think we have to be done with it. I would like to see some sort of analysis this will probably be your best guess from what you have read inthe newspapers of what other MINUTES UAC:12/04/96 FINAL PAGE 9 people will have on both rates and competitive charges so that we will be able to see where we stand competitively. I would like to see some sensitivity analysis of the marketing issues. For example, what happens if we lose two or three big customers? How will that affect us? That is a different sort of scenario. You mentioned its existence, but we don’t have any numbers. How important is that? Similarly, suppose we got two or three big customers from nearby places which we could service easily? How does that affect all of this? Traditionally, in Palo Alto, (a/%d I know you feel this way, Randy) where we have some existing customers, and if one of them should disappear from Palo Alto, some other customer comes in and fills that building and does business with us. That has been our traditional situation. We are moving into an era where Hewlett-Packard could stay right where they are ~and buy electricity from someone else. They could do it on a larger scale than we might be willing to deal with. For example, they might include their Colorado and Oregon facilities in some sort. of larger contract than we would be able to handle. It wouldn’t be that We were the bad guys. It would just be that we would not have the scope to be able to deal that widely. I only pick on them because they are large, and we know they have places outside of California where they do business, but that is’ probably true of many of our.large customers. So I would like to see some sort,of analysis of possible scenarios. Maybe this is where we find our low-low or very~low, whatever you call that scenario. In Table 1 of stranded costs in the report, I see that the Californiam Oregon Transmission Project (COTP) costs are listed as the same, independent of any scenar’ios. Are there any sensitivity issues as far as transmission is concerned? Are there differences in.prices’ there which would cause us to feel that we have more,stranded cost because the prices available for .transmission changed? I don’t know if that is an important issue, but I would like to hear some discussion of that as to why it is or is not a fixed number, and what sort of change is available in that area. . Mr. Haba~hi: Said I will respond to several points, and I.will address the last one first, the issue of transmission. The $60 million that you have in the stallreport right now is just about as pessimistic as you can get. The likelihood is that we will see some stranded costs on the transmission side for a couple of years, but not beyond that. The $60 million is an estimate of what would happen if we have to pay for the COTP. Then everybody else has to pay the market price, which is considerably lower.for good, not just for the next few years. It is very likely that we are going to come back next year and revise that number down somewhat, and that is why setting the rate increase makes a lot of sense. If we do 8% this year, next year we may be doing less than 5~ We may be doing zero. MINIYI’ES UAC:12/04/96 FINAL PAGE 10 The other point I want to address is something that you asked for in the last meeting, and again this time. You wanted sensitivity analysis to address stranded costs, assuming that we are going to lose some of our customers. I feel that is a worthwhile study, so let me try to do a quick study right here tonight. We now purchase somewhere between 25 and 50% of our power needs on the spot market. If we lose somewhere between 25 and 50% of our customer base, assuming that we unbundle our rates and do it appropriately, we should not see an impact on stranded assets. They should work all right, because we will still be charging the customers that will depart our system and buy from somebody else the stranded transition costs. Even if we lose 90% ~of our customer base, which is not very likely anytime soon, but even if that happens, we can always give Western three months notice and cancel that contract. We would still be all right. We obviously would not be making the money that we are making today or making some ofthe transfers that we have been making, but from a s~randed cost calculation perspective, you are not likely to see any change if we lose some of our customer base. Commission~r Sahagian: Said Tom, you answered one of my questions, which was, the non-bypassability of the competitive transition charge (CTC). Your comment about raising rates to cover the CTC potentially impacting customers and-creating a migration from the system, I am trying to understand, with the non-byp.assable CTC and what. the intention of reducing rates, once the CTC is collected, if customers are apprised of that, why would we be concerned that collecting the CTC might drive them from the system? That is an important .q~,estion because we want to try and retain our industrial base. The answer to a second question is probably available if I shuffled through some of the paperwork, but I am sure you have it on the tip of your tongue. The.investor-owned utilities obviously have a .competitive transition charge, which they are going to be levying. I think it is substantially greater than what we are talking about, but I think they are financing a portion of it, and they are mandated to actually reduce rates. My feeling is that it is going to be very important thatwe try to track what we are doing against what is happening in the balance of the market. Even though our philosophy here is, don’t burden our grandchildren with financingthe debt of today and try to put it behind us and get competitive as quickly as possible without encumbering the City and the shareholders, I think financing mechanisms and strategies are being used on the other side of the fence, and it could put us at a temporary disadvantage, potentially. I wonder if you could comment on that aspect. ~: Said what the IOUs’s are doing is, they are giving their residential and small commercial customers a 10% break, and they are MINUTES UAC:12/04/96 FINAL .PAGE financing that over a te~-year period, In a sense, what they are going is saying to their residential and commercial customers, instead of collecting your portion of the stranded cost from you over the next four-and-a-half years, we will collect it over the next ten years. In the process, we will give you this 10% reduction, which you would have gotten anyway if it were not for the stranded cost issue. I think Palo Alto could do the same, but Palo Alto is already discounting the rates to its residential customers quite a bit. So you might say the same thing, but instead of saying, we will give you a rate discount, you might say, we will not raise your rates, and in return, you can pay.it back over ten or fifteen years. Quite frankly, I don’t think it is the prudent way to go. If we are talking about a 7 or 8 or even a 15% increase on the residential side, it will not make any impact whatsoever, given what the competition has to pay today. You may, however, consider doing somgthing for the industrial customers. W1%at you are after here is to keep your large customer base, and you are not as worried about the residential~. What AB 1890 did was that the legislators wanted to give something to the residential folks, because they are the voters. What you may want to do here in order to satisfy your large customers is to perhaps find a way to get the large customers to pay their stranded costs over a number of years that will go beyond the five years, and package that type of a deal with them, along with a few other ~hings you could offer, including ~long-term sales of commodities. So these are the kinds of ideas we will start thinking about, however, we obviously need to establish the rate increase, that will be applied, come July, to everyone, and start from there. If we want to work something out with a sector of the market, then we would do that from a marketing perspective and from a marketing effort that we will be making over the next year or so. Getting to your first question,.if we unbundled, and your CTC is dealt with separately from all of the other rates, why would your customer migrate? In my mind, it is more psychological than it is sitting down and calculating whether they should or should not. If they get a 13 or 14% rate increase at a time when the IOUs are saying, we are holding our rates flat, the marketers out there can use that against us. They can come in here and say, at a time when everybody is either reducing their rates.or freezing them, look at what Palo Alto is doing. You obviously are not seeing what is going on in the market in increasing your rates 15% in order to save a whole lot of more money, the stranded assets.. I think it is more of a good will gesture. By doing that,, your customers can eventually decide to go with the competition instead of staying with you if they see a lot of rate increases coming at them all at once. ~_~l~~:I would like to add that I feel it is important to MINUTES ~UAC:12/04/96 FINAL PAGE ~2 recognize that right now, Palo Alto residents have the lowest electric rates in California. Even if we have to raise rates and PG&E lowers their rates, we are still going to be below PG&E. We actually are on a more accelerated plan here th~n PG&E because of this political solution with AB 1890 to allow residential customers this discount .or rate decrease. Then they are going to be paying off the bonds for another ten years. Our plan is to be totally free of stranded costs by July of 2002. In. your comment, Paul, about the time frame difference of six months, I agree that that could be something we should look at. At this point, this year, I don’t think it is something we are going to plan for, but as we get further down the line, we certainly are going to be making some adjustments. Tom mentioned COTP. We have seen quite a different forecast of numbers between this recent update and the spring. Purchase power costs, for one, are $orecast to go down and stay down for quite a while, which accounts for the reason why rate increases are fairly moderate, even though the stranded cost estimates are relatively higher. On the point about the setup provisions, that is something we are going to be looking at. It gets back to the basic question for anyone dealing with stranded costs. What is your comfort zone? Each person has their own comfort zone as to how conservative we should be. Tom’s point about the low case is a good estimate at this point, because itdoes cover 70% or so of the debt service. But there are other factors that are not addressed in the report. Frankly, the one that disturbs me themost, which no one ’is really talking about, is the possibility of self- generation, since ~that is a total bypass situation. We are not prepared. to deal with that. Does that mean we should start building .up a reserve for that? I don’t think .so, but there are those possibilities out there that we should be’looking at. Chairman Johnston: Said as a final comment tonight, I think the proposed kind of approach that you have talkedabout, with a larger rate increase in the coming year and then a smaller one the following year, seems to be an approach that maintains a considerable amount of flexibility. As you know from running the numbers, whatever you do this year, you get more bang for the buck because you have an extra year to collect on. So clearly, the bigger bite ought to come this year rather than next year. If you do 8 or 9% this year, and the picture changes next year so that you don’t have to do anything, that is great. At least, it maintains a lot of flexibility for the following year. So I think you should be able to work Out something pretty good here. Keep it in single digits, but maintain some-flexibility.Thank you very much.This was a good report. MINUTES UAC:12/04/96 FINAL PAGE 13 MEMORANDUM TO:Utilities Advisory Commission FROM: AGENDA DATE: SUBJECT: Utilities Department November 6, 1996 Updated Stranded Cost Analysis REQUEST This report is informational only. As part of the Calaveras Reserve Policy approved by Council during the 96-97 budget process, staff recommended a further review of stranded costs with the UAC during FY96-97 (CMR:214:96). This report presents staff’s plan to revisit this issue and provides updated estimates of Palo Alto’s potential stranded costs. RECOMMENDATION There are no recommendations and no UAC action is required. POLICY RECOMMENDATIONS No policy recommendations are contained in this report. However, in order to. calculate stranded costs, some policy decision assumptions have been identifed. Also, the technical review and evaluation of stranded costs with the UAC this Fall may lead to policy implications and subsequent actions by the Council. EXECUTIVE SUMMARY During the budget process for FY96-97, the City Council .adopted a policy regarding stranded investment costs for the electric utility. The centerpiece of Palo Alto’s strategy to recover potential stranded costs is to .accelerate funding of a stranded cost reserve (Calaveras Reserve). The current policy provides for funding of the Calaveras Reserve to a target level of $31.6 million (20035) by the end of FY 2002-03. The net present value of $31.6 million was based on $42.1 million in nominal dollars. The level of funding and timetable is to be evaluated annually. This report begins this annual evaluation process. Broadly speaking, the UAC agenda on stranded costs will focus on two issues. They are: 1. What is the appropriate estimate of Palo Alto’s stranded costs and reasonable funding schedule to recover these costs? ’ 2. What are the viable strategies to mitigate risk to the Electric Fund if actual stranded costs beyond the transition period are higher (or lower) than was assumed to be recovered from the stranded cost reserve? In other words, what are the ris "ks if we are too conservative or too liberal in our long-range forecasts? For the next three UAC meetings, staff plans to address these issues. For this November meeting, staff will update calculations of potential stranded costs (Attachment 1), discuss Palo Alto’s additional vulnerabilities, and other related topics. This update will include the following changes from previous stranded cost estimates presented this Spring. 1) In calculating the stranded costs associated with the Calaveras Project, a revised debt service schedule has been used which is lower than the existing schedule. Reduced Calaveras debt. service obligations are anticipated as NCPA plans to refund certain fixed rate series bonds at a lower rate due to favorable market conditions. 2) Besides Calaveras, staff will evaluate the potential stranded costs of other Palo Alto. generation and transmission obligations. In particular, the California Oregon Transmission Project (COTP) potential stranded costs of approximately $16.7 million (in 1998 dollars) have been added. 3) Staff has received long-range electric market price quotes from marketers willing to "buy" power. In order to estimate the price a marketer might be willing to "sell" power, staff has added a 30 percent margin to the quotes. For comparative purposes, a stranded cost estimate based on the market price quotes is provided. 4) An estimate by Merril Lynch of Palo Alto’s Share of stranded costs associated with ttie Calaveras Hydroelectric Project is provided. A total of 6 stranded cost estimates are provided in Attachment 1. The use of the market quotes and the Merrill Lynch analysis accounts for two estimates while four estimates are based on staff’s forecast of market prices ranging from low, medium low, medium, and high that were used earlier this spring. Stranded cost estimates in this report are shown in nominal dollars, 1998 dollars, and 2002 dollars. The 1998 dollars provide the net present value of potential stranded costs incurred during and after the transition period (1998-2024), Thus, total stranded costs are represented. However, the financial strategy to recover these costs involves two pans. First, stranded costs incurred between 1998 and 2001 would be recovered through retail rates, including a CTC. Secondly, stranded costs incurred after 1-1-02 (the projected date that full competition is expected to begin) would be recovered through the Calaveras Reserve. Accordingly, 2002 dollars represent the net present value of potential stranded costs incurred beyond 2001 and is particularly relevant in setting an appropriat~ target balance for the Calaveras Reserve. The nominal dollar amounts will be used in the financial analysis next month to estimate annual withdrawls of the Calaveras Reserve. The following table summarizes the results of this analysis developed by Utflities, Resource Management. Millions (2oo2s) Resource Calaveras COTP Total Staff- Market Price 2002 $ $82.0 $16.4 $98.4 Staff- Medium Low Market Price 2002 $ $42.6 $16.4 $59.0 Staff- Medium Market Price 2002 $ $22.8 $16.4 $39.2 Staff-. High Market Price 2002 $ $ .4 $16.4 $16.8 Market Quotes Forecast 2002 $ $82.2 $16.4 $98.6 Merrill Lynch Estimate a99s $) $69.5 $16.4 diff. $ It should be noted that the above $39.2 million stranded cost estimate based on the staff’s medium market price forecast is the same market, price scenario adopted by Council to establish a target for the Calaveras Reserve. The increase from $3L6 million to $39.2 million reflects the net changes as previously stated, including the COTP addition. For the December meeting, staff will provide a multi2year retail rate plan to fund two levels of stranded costs in 2002 dollars. This involves 28 year financial forecasts based on stranded cost estimates derived from: 1) staffs low market price scenario, and 2) staffs medium.low. market price scenario. If appropriate, other .funding or cost minimization alternatives (restructuring/refinancing debt) will be evaluated to soften rate impacts during the transition window to full competition~ Also, for the period beyond the transition window, staff will present, for purposes of discussion and evaluation,a number of mitigation measures the Electric Utility might consider if stranded costs are higher or lower than had been planned. The measures vary in merit and political feasibility. Examples of mitigation measures include application of a Competition Transition Charge (CTC) beyond the investor-owned utility’sCTC window, extending Calaveras debt payments, and using profits from the sale of power outside Palo Alto. Unless further meetings need tobe scheduled, staff will present its overall recommendation on stranded costs for UAC input in January, 1997. Th~n, the final recommendation by the staff on this subject will be presented to the UAC during the Spring budget process. The staffs recommendation will be contingent upon the City Council approving a number of policy issues related to stranded cost and the issue of direct access in Palo Alto. Staff plans to present these policy issues to the UAC and the City Council before February 1997. For purposes of calculating stranded costs in the attached analysis and as a basis for discussion in the UAC December meeting, a number of assumptions were necessarily made that ultimately will be decided by Council. Some of the policy decision assumptions include: 1. Palo Alto will provide direct access to its customers. 2. Palo Alto will collect a Competition Transition Charge. 3. Palo Alto may partner with other agencies to market its resources and services to retail customers outside of its service territory. 4. The date to achieve full funding of the Calaveras. Reserve target balance is 6/30/02. FISCAL IMPACT No recommendations are contained in this repor.t and there is no fiscal imp’act. ENVIRONMENTAL ASSESSMENT This informational report does not constitute a project under the California Environmental ¯ Quality Act; therefore, an environmental assessment is not required. ATTACHMENT Attachment 1: Stranded Cost Analysis PREPARED BY:¯ Randy Baldschun, Assistant Director of Utilities, .Administrative Services DEPARTMENT HEAD APPROVAL: Director of Utilities ATTACHMENT 1 Stranded Cost Analysis I.Executive Summary This study was undertaken to update the calculation for the range of potential stranded costs for Palo Alto. Stranded cost is defined as the cost of our own resource portfolio and other resource related obligations that are above the market value of those resources beginning January 1, 1998 (the a.ssumed date for offering customer choice). The only significant stranded costs for Palo Alto are from the Calaveras and COTP projects. Other potential stranded costs are discussed in this report, but are not included in the totals shown below. Stranded cost estimates can vary significantly depending upon the forecasts of market prices in the future. Staff used two different market forecasting techniques, to provide additional information for decision-makers. The first forecast was initially developed by an NCPA contractor and was used by staff to estimate stranded costs in Spring 1996. The second was. obtained from quotes received this October from marketei’s for long-term supplies. For comparison, staff also used a forecast of market prices used by Merrill Lynch in an analysis of stranded costs for NCPA. Using the first forecast, stranded cost for Calaveras and COTP is estimated at between $27 and $101 million (in 1998 dollars). The second.forecast yielded stranded cost estimates of $100 million (in 1998 dollars). The largest contribution to stranded costs originates from the Calaveras Project. These calculations include, expected savings from refinancing Calaveras bonds to take advantage of lower interest.rates, however, they do not include other potential liabilities discussed in this report which could further increase Palo.Alto’s stranded cost. Such liabilities include those relating to the possibility of increasing obligations to bond holders if our pa.rtners in the Calaveras, Geothermal, or COTP projects default on their obligations. As of July 1, 2002, strafided costs should be fully collected. The stranded costs for the pe~’iod from 2002 through 2024 are estimated to be between $17 and ~98 million (in 2002 dollars). This is the range of stranded cost estimates applicable to funding a reserve to recover such costs after the transition period. II. Stranded Cost Assessment ’ Stranded Cost Components Definition of Stranded Cost Stranded cost is defined as those fixed and variable costs of resources that are above the market value of the resources. The stranded cost for each resource wasestimated by comparing the total cost of output from that resource (including variable O&M. fixed O&M, and debt sen, ice) to the market price of the output. If the fixed and variable OSiM cost of the res6urce was above the market price, then the resource would be operated at its minimum or must-take level and, conversely, if the fixed and variable O&M cost of the resource was below the market price, then the resource would be operated at its maximum output. The difference between the total cost of generation and the market value of that same electricity production is the stranded cost for that resource. Resources to Include All the generation resources and contracts we have from 1998 onward were analyzed to determine their contributions to stranded costs. Although the COTP project is a transmission project and its costs can be included in our non-bypassable transmission charges, we estimated by how much COTP costs might exceed transmission costs for PG&E customers. Yaluation of Existing Resources A principal Calculation in the determination of an asset’s stranded cost is its market valuation. One way to determine market valuation is to sell the asset. Another is to sell future production from the plant by executing a contract with a buyer who pays up front in return for all production for a set period into the future. These two methods will result in certainty of the resource’s value. Another method is to estimate the value of the future production by forecasting the market price into the future. This method results in an uncertain .value of the resource since future market prices are unknown. If market prices turn out to be high, the value of the resource will be high, but, if future market prices are low, then the value of the resource will likewise be low. .Length" of Time into the Future to Estimate Stranded Costs Stranded co~t determination also must take into account how far into the future the costs and. benefits of the resource in question should be estimated. The evaluation time .period is key to the calculation and must be decided upon in order to estimate the stranded costs of Palo Alto’s generation resources. One approach is tO evaluate resource costs over the expected remaining life of the resource. The downside of this approach is that the uncertainty over a long time frame is enormous. The debt life of the resource is another possibility, although this can be .very long as well. A set time frame of 10, 15, or 20 years may be appropriate given the uncertainty in market prices, regulation, legislation, and technology that can occur in longer time periods. Another alternati:ve is to use the time period until stranded costs decline to zero and to let future ratepayers i’eap any benefits which may accrue. In this approach, each resource and power purchase contract is evaluated with a different time frame for different market price forecasts. Using this approach would not count on the potentially large .benefits which might accrue in later years for projects such as Calaveras if costs are lower than the future expected price for energy. Because market prices are extremely uncertain,as the time horizon is extended, we cannot count on those benefits accruing. If the benefits are realized, the effect of not now counting the future benefits is that customers in the future will reap the benefits of lower than market costs rather than the customers of today. The alternative is to risk .undercollection of stranded costs by assuming the future benefits will accrue. This study will consider only gross stranded costs and 2 wilt not net out future below market costs. Sources of Uncertainty Future Market Price 1.Market Energy Prices Two market energy price forecasts (referred to as Case I and Case II) were used in this study (see Exhibit A). For Case I, staffused market energy prices developed in May 1995 by Henwood Energy Services, Inc (HESI) for NCPA and updated in February 1996 when gas market forecasts were updated. The "high" and "low" forecasts reflect higher and lower market prices for natural gas, respectively, than in the medium case. Case II was developed from marketer quoteg received in October 1996 for long-term supplies specifically for the Calaveras project output to capture the project’s timing of electricity production. The quotes received were quite low since we asked for prices that marketers would buy the power from us for verb’ long-term (through 2024). At this time, long-term supplies are not traded enough to have developed a liquid market. In addition, electricity commodity quotes from marketers for long-term power are assumed to be priced low to protect the marketer from ¯ the risk inherent in long-term commitments. These quotes are a proxy for the market ~,alue of the project’s output, but do not reflect negotiations between the parties. Therefore, staff adjusted the "buyer" quotes received by adding 30% onto the quote in an attempt to reflect higher market prices in the future.. In a May, 1996 proposal for restructuring Calaveras debt, Merrill Lynch estimated market energy prices for the purposes of calculating Calaveras stranded cost. This forecast is illustrated on the attached chart (Exhibit A). In the early years, this forecast seems excessively high given recent experience where market prices are about one-third of those in the Merrill Lynch forecast. Given that the marketer quotes received were on the low side of the NCPA forecasts, staff developed another forecast between the Case I low and medium cases. This "medium-low" case ~vas also used to calculate stranded costs and is shown’on the attached chart (Exhibit A). 2. Market Capacity Prices For Case I, staff used market capacity price forecasts also developed by HESI in May 1995 (see Exhibit B). Staff adjusted that forecast to create a "high" forecast which is represented by. a rather steep incline from Current market costs to 2002 when a reg!onal load and resourcesbalance is assumed to occur. At that time, the price represents a high value for new combustion turbine. (CT) capacity. The "medium" forecast for capacity assumes regional load and resource balance in 2010 when it reaches a price equal ico the cost to build new CT capacity. After load and resource balance in the medium and high forecasts, the price increases at the-inflation rate. The "l~w" forecastescalates the current market capacity price by inflation. 3 Market capacity price forecasts for Case II were embedded in the marketer quotes for firm energy. Calaveras Prqiect It is anticipated that the Calaveras bonds will be refinanced within the next 18 months and the expected interest payment savings of approximately $8 million (in 1998 dollars) are incorporated in the analysis. The debt period was assumed to be unchanged for this analysis. Western Resource Given that Palo Alto is capable of terminating the Western agreement with 3 months notice, the cost of the Western resource should have no impact on the calculation of the stranded costs. The decision whether to terminate or not will obviously be made by using appropriate assumptions regarding future electricity market prices and Western costs. Washington Water Power The WWP contract was terminated (5 years termination notice) in January of 1996. The NCPA Commission has approved an early buy-out with an up-front payment of $17 million (Palo Alto’s share is $2.2 million) to WWP. This early buy-out will be funded from the current power purchase budget and therefore has no impact on the calculation of stranded costs. Bonneville. Power Administration The BPA contract expires in 2004, unless terminate~l.early. The earliest possible termination date is in 1998. Since the stranded costs were lowest if terminated earl3’, igiven the estimates of market prices, itwas assumed that we would terminate it at the end of 1"998. In all cases, the BPA contract has little or no impact on stranded costs, so staff recommends removing this resource from the stranded cost analysis. California Oregon Transmission Project The above market cost for the COTP was estimated by comparing the total cost of the COTP, including debt, fixed O&M and overhead, to the.estimated market value of transmission. The market value of transmission was assumed to be PG&E’s rate as published in their 1995 Open Access Tariff (OAT). ~ COTP costs other than debt service were assumed to escalate at 5% per year. PG&E’s transmission rate was assumed to.escalate at 2% per year. Given these assumptions, the above market cost of COTP from 1998 through 2024 (when COTP debt is retired) is estimated at approximately $16.7 million (19985) for the base case. The actual COTP above market costs are uncertain since they depend upon the market value of transmission and the credit we obtain for the value that the COTP provides to the interconnected electric grid. At the FERC and CPUC, proposals that may determine the credit issue are being discussed. The outcome of this process ishighly uncertain. It is possible that the COTP project investors will get the full value of the investment credited in the credit proceedings. In this case, the above market cost for COTP would be zero. It is also possible that the market value of transmission will be lower than PG&E’s OAT. If the market value of transmission is 90%-of 4 PG&E’s OAT and COTP costs other than debt were to escalate at 7%/year, the above market cost associated with the COTP project would be $19.8 million. These uncertainties are believed to be uncorrelated with the power market price uncertainties, so staff recommends using the base case COTP stranded costs for al! power market forecast cases. Other sources of.uncertainty There are ma.ny other potential changes that could change stranded cost estimates including new regulations or legislation, other NCPA member activities, and Calaveras production (hydro year). IIl. Palo Alto’s Stranded Costs As expected, the stranded cost estimates are extremely dependent upon the market price estimates. To represent the uncertainty in market price forecasts, the results are presented for the two market pri~:e methodologies as well as for the Merrill Lynch forecast. The charts below show the discounted (in 1998 dollars) cumulative stranded costs for the Calaveras and COTP projects, since these resources represent the only significant stranded costs for Palo Alto. Palo Alto’s Cumulative Generation Stranded Costs Palo Aito’s Cumulative Transmission Above Market Costs $1998 (xl000)High COTP 0 PG&E Transmission Cost Low Bas’e 19,800 16,700 Palo Alto’s Additional Vulnerabilities There are potentially additional sources of stranded costs for Palo Alto. There are certain risks as the electric utility industry moves towards competition that threaten Palo Alto’s competitive position. One is the "step-up" requirements that exist in our contractual relationships with other NCPA members who jointly mvn generation and transmission resources. If, for example, one or more of the other member-owners of the Calaveras project defaults on their repayment Obligations for some reason, then the other members, including Palo Alto, must step,up to cover the defaulting member(s) obligation. The maximum amount for any member to step-up is 25% of their original obligation. Therefore, Palo Alto is exposed to some additional stranded costs from these contract provisions. The resources for which Palo Alto is at risk include the Calaveras project, the Geothermal project, and the COTP project. The additional stranded cost due to the step~up provisions depends upon when the step-up occurs and the amount of step-up that must be endured. The earlier the step-up and/or the higher the step-up level, the greater the additional stranded cost. Note that membei’s may be more at risk of defaulting due to the increasingly competitive nature of the industry and the possible need to raise rates to collect stranded costs in a short time frame which makes them appear even less competitive. It is necessary for Palo Alto to understand the competitive positions of and the risks facing the NCPA members as their actions could increase our exposure. In the worst case of maximum step-up (25%) occurring in 1998 or before, Palo Alto’s stranded. cost estimates would increase by $12.5 million assuming the medium-low market scenario is realized. The additional Calaveras stranded costs are as shown in the table below for various step-up fractions if step-up occurs in 1998: Palo Alto’s Additional Calaveras Cumulative Stranded Costs for 1998-2024 Due to Step-Up Provisions (1998 Dollars X 1000) Calaveras Step-Up Fraction Market Quote plus 30% Low Market Forecast Medium-Low Market Forecast Medium Market Forecast High Market Forecast 5% 4,200 4,200 2,500 1,700 5O0 15% $12,500 $12,500 $ 7,50O $ 5,000 $ 1,600 25% $20,800 $20,800 $12,500 $ 8,400 $ 2,700 The Geothermal project may also impact Palo Alto’s competitive position. Palo Alto has transferred all of its rights and obligations of this project to the Turlock Irrigation District (TID). IfTID goes bankrupt, Palo Alto may have to assume the obligation of the bonds. Ifa Geothermal project participant other than TID defaults, then TID is liable for the 25% step-up provision. Since the fixed O&M costs for this project are so high relative to market energy price projections, in most years the project would not necessarily be operated. Therefore stranded costs for this project consist almost entirely of the debt which is retired in 2010. Thus, stranded costs for the portion of the project which Palo Alt0 laid offto TID total about $68 million assuming the medium-low scenario (NPV in 1998 dollars). If an additional 25% step-up obligation were required, then Palo Alto could be responsible for an additional $17 million for a total worst case liability of $85 million. However, the likelihood of being forced to pay for the entire amount is ven." low. Palo Alto’s contract with TID is unequivocal in stating that TID is obliged to make payments for their share of the geothermal project regardless of whether the project is in operation or not, Total Estimate of Palo Alto’s Stranded Cost It is unlikely that either TID or other NCPA members \vould default on their bond obligations. " Therefore, staff recommends that we not include these potential liabilities in calculating our stranded.costs. Similarly, because the analysis shows that the stranded costs for BPA are less than $200,000 in the worst case and zero for other cases; staff recommends that the stranded costs associated with BPA not’ be included and that we concentrate on the’ significant stranded costs deriving from Calaveras and COTP. Not including the potential step-up liabilities; the. table below shows the potential stranded costs for Cases I and II for Calaveras and COTP in nominal dollars. The "base" above market costs for COTP are shown in all cases since the transmission value is not related to the market price for energy. Stranded Costs for Calaveras and base case COTP in nominal dollars (X 1000) 1998 199’9’ 2000 2001 ’2oo~ 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 $6,200 $’6.000 $5.900 $5.800 $5,900 $6.000 $6,000 $8,300 $8,300 $8,300 $8.200 $8.100 $8.100 $8.100 $8.100 $8,100 $8,000 2015 $8.000 2016 $7.900 2017 $7,800 2.018,$7,900 2019~.......sg.o00 2020’$8,100 2021 .$8,200 2022,$g.200 2023 $8,100 ’20241 ....$3,000 CPA bl arket Forecast b,l arket M ed-Low [/M edium 1 II igh Quotes" $5,800,1$5,500 $5.200’! $5,000 54.900 $4.900 $4,800 $6.400 $6.000 $5.700{ $5.400 $4,900 $4.400 S4.400 $4,300 $4.200 s4.ooo $3.900 $3.700 $3.400 {,,, $3.300 $3.200 $3.200 $3,1’00 $2,900 $2,700 $1,500 55,3oo $5,100 $4,700 $4,600 $4,500 $4.300 $5.400 54,900 $4,400 $3.700 52,900 52.100 $2.00’0 $1,800 $1.600 51,400 $1.300 $1.300 $1.400 $1,400 51.4oo $1,400 $1,400 $1.500 $1,500 $1,500 $5,100 $6,100 $4,300 $5,900 $3.400 $5,800 $2,400 $5,700 SI.300 $5.700 51.200 $5,800 $1,000 $5.900 ${.200 $8.000 sl.20o $8.ooo Sl.200 $8.000 si.3oo $8.ooo St.300 .$8.1’00 SI,300 $8,100 $1.300 $8,200 $1.300 $8.300 51.300 $g.200 51.300 $8,300 SI.300 $8,300 SI.300 $8.200 SI.400 $8.100 sl.400 $8.2oo S~.400 $8.300--- S~.400 $8.400’ s1,400 58.560 51.~oo $8.5oo "$1,500 $8.500 51,500 $3.400 The chart below’represents Palo Alto’s stranded cost estimates after the transition period (1998- 2001 ) has ended. The stranded costs are shown as the net present value in 2002 dollars for the period from 2002 through 2024. Stranded Costs For Calaveras and COTP for 2002-2024 (NPV in 2002 dollars) NPV ($2002) Calaveras COTP Total Low $82,000 .s~,400 $98,400 CPA Market Forecast Med-Low’Medium High $42,600 $22"1800 $400 $16,406 $16,400 SI6.400 $59,000 539,200 SI6.800 "’ M~rket -- Quotes S82,200 $16,400 $98,600 IV.PG&E’s Stranded Cost Estimates Our competitiveness relative to PG&E is important and more analysis needs to be done to determine Palo Alto’s position relative to PG&E’s. The California legislation regarding electric industry restructuring, AB 1890, addresses investor-owned utility (IOU) recovery of stranded investments. Under AB1890, IOUs such as PG&E are allowed full recoveU of stranded costs through a Competition Transition Charge (CTC) which will be nonbypassable and levied on all customers on a usage basis. In addition, AB 1890 dictates that stranded costs must be collected under certain rate cap restrictions. In other words, the amount that the IOUs can devote towards stranded costs is that amount collected in their current rates less their expenses. The IOUs can collect CTCs from all customers from January 1,1998 through December 31,2001. The IOUs are at risk if they cannot collect enough under the rate cap restrictions in that transition period. The rate cap restrictions also include guaranteed rate reductions for residential and small commercial customers. The amount of stranded cost that the IOUs cannot collect due to these rate reductions for residential and small commercial customers in the. transition period can be .financed with a bond. Thus, for these customers, stranded cost collection can continue until these "rate reduction bonds" are retired. The IOUs have submitted estimates of their stranded costs only for 1998 to the CPUC. They have provided no long term stranded cost estimates. The market rate estimates they provided are only for 1998 rates and were provided for illustrative purposes only. An annual true-up after each year of the transition period will show the IOUs’-progress in their stranded cost.recover?’ by using the actual after-the-fact market prices to determine the portion of stranded costs paid off each year. The incentive for the IOUs to cut costs is clear since all revenues above costs can be devoted to paying down their stranded costs. It is also possible that stranded costs will be paid off earlier than December 31,2001 (especially for large customers), all~wing the early removal of CTCs. Attachments: Exhibit A Melded Market Energy Price Projections Exhibit B Market Capacity Price Projections Prepared by: Jane Ratchye Reviewed by: Tom Habashi Dbug Boccignone i (HAt)I/S) ~!~a-,(~,=au 3 x as outlined in your staff report. With PG&E, over 350,000 customers statewide have been helped over the years by this program. In Texas, the Lone Star Gas Company reports that they have helped 29,000 customers. Inc~dentally, the Salvation AMy al~e~dy helps a number of Palo Alto residers, but the source of theiri~unds is outside of Palo Alto. The REACH p~ogram that is collecte~y PG&E customers has been .Salvatmon AMy people, andallocated to t~ ~ocal Palo Alto /’ ~fort~ately, they ru~ out of those f~s during the year. Presently, there ms an mnsufficien~ount, so ~ this progr~ does get approved by the City, we can eitheg~replac~hose funds with our o~ citizens helping our o~. citizens, or\we q.a~ supplement those f~ds that they are allocated by their o~ offi~i I am delighted and pleased that this program is being considered2~the UAC and by the Palo Alto Utilities Department. I can share/~ith~you that I fully support the staff recommendation. Thank.jvery~ Chai=an Johnston: .ynk you, Mr. Le~ MOTION: Commissioner Eyerly: I m~ve approval of the staff SECO~: BY C~issi°ner Sahagian"-" _ ~.MOTION PASSe: Chai~an Jo~ston: T~ motion pas%es ~an~mously on a vote of 51~. Item 7. d.Electric Utility Stranded Cost.Update Mr. Baldschun: Earlier this spring, as you know, we spent some time on the subject recommendations that council approved, one of which was that we review this matter again this year with the UAC. That is why we are here tonight to. begin the first of three meetings on stranded costs. Tonight we have a report that outlines our approach to the subject and how we plan to approach it over the next three meetings. We also have Attachment 1 that was performed by Jane Ratchye and Doug Boccignone with Tom Habashi’s review on. the updated stranded cost estimates. They can answer specific questions in that area, and I will try to .answer questions on the agenda items and how we plan on addressing these items. Next month, I will primarily be addressing the mitigation measures that we want to bring to your attention to engage in a dialogue, specifically, what happens if the staff is wrong in our forecast and we underestimate or overestimate stranded costs, what options are available to the City? This is something that we danced around in the spring. We did not spend much time on it, and I don’t know if any of us sitting here tonight have definitive answers tonight or next month, but we want to attempt to look at these thingsand try to get a comfort zone for MINUTES UAD:I 1/06/96 Final Page 29 them. In order to recommend a stranded cost plan, you need to have some sense of the risk involved if you are wrong. One other comment I wish to make is that the current council policy is that we will establish a balance in the Calaveras Reserve by the end of 2003 of $31.6 million. As you know, since the spring, AB 1890 has come out, and now they have moved it up a year, essentially for the investor- owned utilities for fall, open competition in 12/31/01. So we have updated the stranded costs numbers to include what the target balance in the Calaveras Reserve would be in 2002 rather than in 2003. There are some other changes that Tom’s group is going to talk about. Mainly, the COTP is in there this time. Also, the there are some refinancing asstunptions regarding Calaveras that have an impact on the numbers. There are also some policy decisions that we plan to bring before the Council that really have to be made before any final action can be taken on the stranded cost policy~ The plan is to get those to the council and to you prior to the final de~ision on stranded cost. Chairman Johnston: Tom, are you going to make a presentation? Mr. Habashi: We do not have one but we are ready to respond to your questions. I have one thing to add to what Randy said. I want to emphasize that next month, in addition to the stranded cost investment, the stranded cost report that you will be getting from Randy addressing mitigation measures and recovery measures, we will also be bringing in recommendations for certain policy issues that need to be addressed by the council in regard to customer choice and asse~, investment recovery, as well as sales. We are working on that right now, and we hope to be able tobring it tc you in December. Chairman Johnston: . Could I begin by trying to get a gut level feel of where we think we are now? I understand that a lot more work needs to be done, but when I look at Exhibit A, I wonder if I am reading it right or wrong. The way I look at it, it appears that maybe my worst fears have been realized. When we had.this issue here before, we had talked about a projection of how fast the energy prices would rise and that if we were going to have relatively low stranded costs, it would depend upon our having a fairly steep climb in energy prices. You show the four different levels that we had talked about before for the City of Palo Alto, and then there are these two other lines which, at least to a first order, m~rror the City of Palo Alto low-estimate cost for low energy prices therefore being the stranded cost high estimate. If I understand this correctly, that seems to be telling us that the projection is as bad as we thought it could have been. To make matters even worse, we knew we had a limited time period. We missed a year in~ MINUTES UAD:I 1/06/96 Final Page 30 terms of hotincreasing electric rates last year. We potentially are losing another year, because instead of trying to get this done by 2003, it is now 2002, so we have basically lost a year there. Am I missing the boat or is it pretty bad? Mr. Baldschun: What you have this time that you did not have before is a forecast of energy prices that is a proxy for market prices from a marketer. That is one estimate. That is not an estimate which we have tried to turn into a high, low, medium. It is simply their e~timate, and we have added 30%, which turns out tobe a relatively low market price which is close to the market price that staff forecast back~in the spring. The other one that you have, The Merrill Lynch estimate, is similarly low, although a little bit higher than the marketers. ~I think it is premature to conclude tonight whether it is worse or better. think you will get a sense of that after having gone through this exercise over three months. You can look at the high end of the range and you might say, what are we worrying about in terms of the market prices? Again, it gets down to where you feel you are given information, given the mitigation measures we are going to come to you with next month. You are correct in that the window has shortened and when we can enact rate increases. We decided that we did not want an increase in rates last year. Of course, with AB 1890, they have shortened it one year, so that window is shorter. The question is, is that a nightmare? Well, we will find out next month when we show you the rate projections. Chairman Johnston: I understand that you are not done with your analysis, but we do not have a final number yet. Obviously, we have more work to do here, but it at least looks like we are going to go back to the City Council with a significantly higher target over a shorter time period. It seems to me that we would be saying that we are going to be recommending that we~need to increase rates. Mr. Mrizek: That is a possibility. As Randy indicated, we are doing an analysis now at staff of looking at our current rate, the expenditure we require at this time to purchase our energy, and our supplies over the next three to five years. Tom and Doug and their staff will be doing an analysis of that. We know that the market is soft. We want to look at whether that market will remain soft over. the next several years. Possib~ly there will be some dollars available there to put into reserves rather than to apply to purchases. As I said, staff is looking at that now, and we are looking at some other options for generating revenues if we have to increase Calaveras Reserve well above the $31 million figure we recommended last ~earo We will .be bringing to you some alternate options on how to increase the reserve, if absolutely necessary to reach the target by 2001 or 2002. We still do not have all of that MINUTES UAD:I 1/06/96 Final Page 31 information. We want to bring that to you over the next two months. Mr ..... Habashi: Chairman Johnston, I would like to make one point to put your fears at ease a little bit. The reduction of the Western allocation that we did a couple of months from 175 to about 130 allowed us to go to the market quite often on the spot and buy cheap energy to replace that of Western. So over the next four years, we may be looking at some good amount ~of dollars coming in via that reduction of the Western allocation. Even if the market is high, we should expect that the stranded costs would be low, therefore, there is a balance here due to the fact that we have gone on the spot market quite often. If the market is very low, then the stranded cost is high, but if we go on the market, that reduces our production cost and increases our savings. I think you will-see when we come to you next month that the rate impact is likely to be minimal. Chairman Johnston: I look forward to that. C0mmissi~ner Sahagian: I thought this was a pretty well prepared brief. However, I do not completely understand what we are saying in Exhibits A and B. When I read this analysis, the first thing that came to mind, if you were to amortize the stranded investment over some period of time and divided by the total number of kilowatt hours that we would expect to generate at current consumption levels, what does it mean in terms of cents per kilowatt hour? The numbers that have been bandied about in the deregulation hearings have been in the range of four to four-and-a- half cents for California investor-owned utilities. That is what the competitive transition charge (CTC) hasbeen projected to be. When I looked at these graphs, I thought I might be looking at something that put it into those terms. I’ do not completely understand what we are saying in Exhibits A and B. Could someone clarify what these exhibits are saying? When you say, ~Energy Price in Dollars per Kilowatt.Hour" what is that? Ms. Ratchye: First of all, the label is wrong. It should say, "Dollars per Megawatt Hour." I realize that could cause confusion. The CTC material you will see next month. This has nothing to do with that. This only shows various market price projections to show the uncertainty in forecast. Commissioner Gruen: I just read it all as mils, therefore, it all made sense. I have some more basic questions. On the first page, you talk about 2003 dollars rather than 2002 dollars. Are these different units, like 1998 dollars? Or is that just a change in target date that you are talking about? MINUTES UAD:11106/96 Final Page 32 Mr..Ba!dschun: . It is a change in target date. 2003 was relevant in the spring when we adopted the policy. It is no longer relevant for purposes of this new analysis. Commissioner Gruen: Is there a discount rate you use in calculating these? If so, what is it? Ms. Ratchye: Six percent. ~.ommissioner Gruen:How do you get six percent? Ms. Ratchye: I got that from Lucie who said it is the rate of return on our portfolio. ComInissioner Gruen: earlier. Well, it was 7% when we were talking about that Ms. Ratchye: I heard that, too. Commissioner Gruen: And it is 5% when we talk about how much the expenses increase each year. I do not have a crystal ball, but I think it would be easier if we picked some number that everyone could agree upon, and start with that. As I understand stranded cost, there are really two calculations going on here. One up here is.what we actually have to pay, and then there are these various market estimates of what we think we can take in in revenue or revenue net of costs to produce that revenue. The stranded cost is the difference between them -- how much we don’t think we will be able to pay in mils per kilowatt hour~or whatever unit you want for it. I asked several months ago what the Calaveras bonds would cost. What is the top number of all of this? How much are we.on the hook for? Mr. Habashi: We are at a little over $120 million. today. Commissioner Gruen:Is that through 20247 " That is outstanding Mr. Habashi: That is correct. And if we keep paying it in nominal dollars, it probably grows to about $240 million or $250 million. Commissioner Gruen: those numbers be? If that gets refinanced, as you expect, what will ~u~_~[~l!: In this staff report,, we are including the assumption that we would be able to refinance those bonds that we actually can MINUTES UAD:I !/06/96 Final Page 33 refinance. There are some that we cannot refinance at this point; The assumption we are making is that we would be able to refinance them from the current 7-i/4% down to 6%. That brings down the stranded cost by about $9 million, I believe. Jane tell me it is $8 million. .Commissioner Gruen: You said that is stranded cost. What is this total number we are going to have to pay over time? Ms. Ratchye: The principle would be the same. With the stranded costs, savings would be the,same as the savings from the refinancing. Commissioner Gruen:. That makes sense. There is an IRP in here, after a fashion. On Page 4, you talk about various contracts and you like this one but don’t like that one. Presu~nably, there is a cost for energy associated with each of these contracts. Can you give me a quick run-down on how much we are talking about? These guys want 40 mils. Those guys want 120 mills, or whatever it might be.~ Mr. Habashi: Are you talking about the list of projects on Page 4? Commissioner Gruen: ..Yes, the various projects. You say you do not want Washington Water Power, pFesumably because it costs too much. Mr. Habashi: That is correct. Commissioner Gruen: That is the softof thing I am asking. the prices that go with these companies? What are Mr. Habashi: Are you looking at rates for dollar per kilowatt hour? (Yes) Roughly, the WWP is probably a melded rate of about 4-i/2 to 5¢. The Calaveras Project in an average year is about 8¢. Bonneville Power ranges anywhere from 9 mils per kilowatt hour in May to 25 mils in August, September and October. The California Oregon Transmission Project is about $3.00 or $3.50 per kilowatt month. Western is ranging today 25 mils.per kilowatt hour, if you add the CVPIA cost, or 2-1/2. Mr. Baldschun: I would like ~to caution the Commission on one item, CTCs. I don’t want us to get started off on the wrong foot. We are not planning on coming to you next month with a CTC cents-per-kilowatt hour figure. That will come when we unbundle the rates later in the spring with the rate proposals. The PG&E CTC formula is rather complex. Other utilities that have formulae for CTCs will probably be uniquely designed for their situation. Conceptually, the way I see our CTC is that there are two components. One is. the stranded costs that occur in the year in which you have the rate effective. So in 1997, we have some stranded ,costs calculated. Those can be translated into a rate.per kilowatt MINUTES UAD:I 1/06/96FinalPage 34 hour. Beyond that, you have the transition window that goes from 1998 through 2001. That is also a stranded cost that our customers are going to be paying so that we can build up the Calaveras reserve. So there are really two parts to the CTC for Palo Alto. It is not just a one- year number where we are going to collect what they have, because there are obligations that gobeyond that. In fact, they go until 2024. We are just bringing them all forward to 2002. Commissioner Eyerly: I do not have much to say on the ’report. I appreciate the amount of work you are putting into the work and on stranded costs and bringing the UAC along with you. I know that some of us were concerned last year that we should have transferred more money to the Calaveras Reserve, realizing that stranded costs were an issue that we have to take care of. But I know it is not that easy to convince the council, outside of Dick, that it can justbe done that easily. I think the reports you have started on, and with what you have told us tonight of the other meetings, we should have something substantial and supportive when you get through. So I appreciate that youare on the right track. We don’t like the window closing down, but I know you are going to come back with recommendations to solve all of this for us! Commissioner Sahaqian: Now that I understand the tables a little bit better, I have some more comments. One of the things that became very apparent to me, in working wi.th Tom in trying to prepare for the City Council meeting, was that the bad news is that we have the stranded investment, but the good news is that once we pay the debt down, it is going to be a very competitively priced asset. I appreciate what you jus~ said, Randy, about the complexity of calculating CTC. However, when looking at trying to develop a methodology for collecting the funds to pay down the debt, in addition to a hard dollar amount that you are collecting over a period of time, it would be most helpful if we could have it somehow~couched in terms of -- if you were to look at that as being something you collect as part of your rate, what does it mean in terms of cents per kilowatt hour that you would have to generate over that period. That puts it into a much more tangible and understandable. context whenlooking at it and trying to get a feel for it, speaking for myself, at least. What does it really mean if we go out between now and 2002 and try to recover these costs? Otherwise, we are going to have to sit here with calculators and multiply megawatts times hours per year to try and get a feel for that~ Mr. Baldschun: We are planning to give you the two worst case scenarios, the low market price and the medium-low market price, given the Commission’s comments this spring that you felt we were too conservative. So you will get a sense of the rate impacts. The rates, I~IINUTES UAD:I II06/96 Final Page 35 like all rates, will include all of the revenue requirements. There are a ~number of~changes to our expenses and revenues, so you will see the net impact. Tha’t is really what the customer is going t~ see. When we break out the CTC, that will be identified on the customer’s bill. They will be able to see that and will know what it is. We will tell them that we are going to take it off at the end of 2001, that it will be eliminated. I am not ready tonight to say we can calculate the CTC in time for next month, except maybe a ballpark figure. You could do a back-of-the-envelope figure simply by taking the 1997 ~stranded cost estimate and dividing it by the total kilowatt hours, which are around one billion. That will only give you a CTC for that year. Beyond that, you have to take the net present value of the stream of stranded costs from 1998 to 2002. Tom just showed me a figure of one cent per kilowatt hour, so I guess that is it. Boccignone: Regarding Tom’s number, we did a back-of-the-envelope last spring, and it was less than one cent per kilowatt hour for us. It would be comparable to the 3-1/2 or 4-1/2 you have probably seen ~or PG&E. In terms of a forward looking basis to make that comparison~ it is going to be difficult. AB 1890 changed the thinking about CTC by establishing this rate cap. The~IOUs are going to calculate how much money they are putting into the CTC account each month, but it is not going to be a fixed amount. It will just be the difference between their current rates and their cost. So they are actually going to kind of back into it. By the end of the collection period, they are going to check and see if they collected enough. If they over collected, they will refund; if they under collected, they get a few more years to catch up. Commissioner Sahagian: Was that one cent figure on the basis that we would recover the entire capital but would need to be repaid for Calaveras and the transmission by the year 2002? Mr... Habashi: I will tell you very roughly how I calculated that in my head. I figured that even in the worst case, if we have a stranded cost of about $80 million and we have $40 million already, .then you need to collect another $40 million over a four-year period. So you need to collect $I0 million every year for four years. If our consumption is about one thousand gigawatt hours, then if you.divide the $I0 million by a thousand gigawatt hours, you get about a penny per kilowatt hour. ~.hairman. Johnston: It seems like a .good analysis. I like it. If I could take it one step further, that is, roughly speaking, a 15% increase, all things being equal. I understand that you might have savings, becauseenergy prices might be low during that time, and because of that, you could offset some of that, but all things being MINUTES UAI~:I 1/06/96FinalPage 36 equal, it is of that order of magnitude. Mr.. Habashi: Correct. Chairman Johnston: Thank you very much for the report. It is a very good start on this process, and as we have identified before, it is one of the most important processes. We appreciate it. City of Palo Alto City Manager’s Report TO: FROM: HONORABLE CITY COUNCIL CITY MANAGER DEPARTMENT: UTILITIES DATE: SUBJECT: SEPTEMBER 26, 1996 CMR:411:96 SUMMARY OF CALIFORNIA LEGISLATURE’S ELECTRIC RESTRUCTURING .BILL, AB 1890 RECOMMENDATIONS This report is informational only and requir.es no action from the City Council at this time. ¯ EXECUTIVE SUMMARY BACKGROUND On April 20, 1994, the California Public Utilities Commission (CPUC) issued.a proposal to restructure the electric utility industry ’to provide for greater competition in’the electricity generation business, thereby reducing the overall rates for California industries, businesses and residents. In Mai’ch 1995, the Federal Energy Regulatory Commission (FERC) initiated discussions to promote grea~er competition nationwide, by making access on the nation’s transmission network readily available to all electricity suppliers. FERC’s action was a clear indication of the Administration’s support to the CPUC in particular and to the deregulation of the electric ’- industry in general. Since the CPUC initiated the deregulation process, state legislators have closely monitored the restructuring process with the intent to enact legislation at the appropriate time. In the spring of 1996, the California legislators formed a 6 member bipartisan committee (3 Assembly Members, 3 Senators, 3 Democrats, 3 Republicans) to draft a comprehensive bill to deal with all aspects of the California electric industry .deregulation. On August 5,1996, the Committee began its hearing on the issues related to the restruettuing. Members worked tirelessly with all interested parties (including municipal utilities) and allowed the parties to negotiate principles that formed the basis for the comprehensive bill. On August 30, 1996, the California.Assembly and Senate unanimously voted to approve AB 1890. The bill became effective on September 24, 1996 after it.was signed by Governor Wilson. DISCUSSION Summary of AB 1890 Currently, electric energy is sold to regulated utilities with exclusive service monopolies. This bill will help to end utility monopoly on generation and open the market to competition, so that retail customers can select the supplier of their choice. The transmission and distribution of electricity will continue to be regulated monopoly services. The attached exhibit provides details on actions required by Investor Owned Utilities (IOU’s) and Municipal Utilities. To ease the transition to a more competitive environment, the bill deals with four key issues. These four issues are: The recovery of transition costs,. Organization of the new market structure, Ensuring system reliability, Funding of public purpose programs, Transition costs. Transition costs are the continuing obligations for past utility power plant investments and power purchase contracts that will not be recovered in a competitive generation market (such as the debt service obligations for the Calaveras project.) The bill provides for full recovery of these costs through a charge, called the Competition Transition Ch~irge (CTC). CTC will be levied on all consumers in proportion to their consumption. Market Structure. The establishment of a competitive market structure with transparent market prices is critical to the success of the industry restructuring. The bill establishes two nonprofit market institutions, an Independent System Operator (/SO) and a Power Exchange (PX). The ISO will control and provide for th~ efficient use of the state-wide transmission grid. The PX will provide for a competitive electric energy auction. A five member oversight committee, made up of three gubernatorial appointees and two non-voting members appointed by the Senate and the Assembly, will oversee the activities of the ISO and.the PX and appoint governing boards broadly representing California electricity users and providers. The bill requires that the IOUs and POUs commit control of their transmission to the ISO and to jointly advocate transmission pricing methodology before.FERC. The bill authorizes direct transactions between the IOUs retail customers and energy providers by January 1, 1998. The bill provides the POUs with the options of allowing choice in their service territory. If the POUs elect not to embrace customer choice, then all provisions dealing with recovery of CTC would not be applicable to them. Q System Reliability. The bill directs both the ISO and the CPUC to adopt inspection, maintenance and replacement standards for all transmission, and IOU distribution systems to reduce the potential for system-wide outages, such as those that occurred on July 2, 1996 and August 10, 1996. In the event of an outage that affects more than 10 percent of a service territory, the ISO is required to conduct an investigation of the utility’s practices and levy appropriate sanctions on non-performing participants. The bill also requires that the ISO, in consultation with other Westem regulatory bodies, conduct an exhaustive reliability study of the Western electric system within six months of receiving FERC authorization. Finally, AB 1890 promotes entering into agreements with neighboring states requiring utilities, that sell power to California, to adhere to protocols and standards to protect system reliability. Public Programs. The bill confirms Califomia’s commitment to renewable resources, energy efficiency, public goods and research and development programs. These programs would be significantly curtailed in a competitive environment. The CPUC and the CEC will determine the details of how to fund these programs for the IOUs. POUs will retain their authority to collect and direct the expenditure of these funds. These charges will be shown as a line item on the utility bills. What AB 1890 Means for Municipal Utilities There are several differences as to how AB 1890 treats the IOUs and the POU, as outlined in the attached exhibit. The most important difference is that AB 1890 does not compel the POUs to allow open access (customer choice) to their customers. However, a POU must join the ISO and allow customer choice to receive the State sanction CTC recovery. Ifa POU elects to provide for customer ~hoice, it must begin the process by January 1, 2000 and conclude it by 2010 ( 8 years later than the IOU’s). The bill confirms the POUs’ existing, rate making authority, allows the POUs to direct the expenditure of the "Public Benefit Charge", and compels the IOUs to . jointly work with the POUs to advocate to FERC a pricing methodology for the Independent System Operation that results in an equitable return on capital investment in transmission facilities. What AB 1890 Means for Palo Alto Like most of the other municipal utilities, Palo Alto’s electric utility (PAEU) needs ,to establish broad policies to deal with the deregulation of the electric utility industry. These policies will need to address these questions: Should Palo Alto allow its customers to choose their electricity supplier? If customer choice is allowed, what is Palo Alto’s CTC and how will it be collected’~ Should Palo Alto market its resources and services outside of its service territory? Addressing these policy issues early will put Palo Alto in a favorable competitive position and improvePAEU’s ability to provide the superior services that its customers have come toexpect over the years. NEXT STEPS Staffhas already begun to examine PAEU’s options, and will work through the Utilities Advisory Commission and solicit Council’s guidance to these important policy decisions. Following the UAC and Council input and direction, staff will prepare a detailed implementation work plan outlining the work products and delineating a schedule to complete that work. ATTACHMENTS Attachment A:Detail Summary ofAB 1890 Prepared by: Tom Habashi, Assistant D)reetor~ff Utilities Department Head Approval: EDW~t(/’D J. MP~EKk" Direct/or .of Utilities City Manager Approval: Topic CTC Recovery Direct Access Phase-In Non- Bypassable CTC Reciprocity Rate Reduction Rate Reduction Bonds Detailed Summary of AB 1890 ATTACHMENT "A" IOU’s Munis IOU’s collect CTC from Indust & Lrg Comm. from I11/98 - 12/31/01. Residential and small commercials pay CTC until rate reduction bonds are paid off. Start Phase-in by I/1/98 Phase-in completed by 12/31/01 CPUC will review phase-in plans and set phase-in schedule (p 42) Within the Direct Access Phase-in period no person, corporation or munis can provide electric service to an IOU (Sr Muni) customer unless a severance fee (nonbypassable CTC) is paid to the original electric supplier. (p 90) There are several exceptions to the CTC rule for.irrigation districts, BART and for self generation. "No local publicly owned electric utility or electric corporation shall sell electric power to the retail customers of another local publicly owned utility or ele~:tric corporation unless the first utility has agreed to let the second utility make sales of electric power to the retail customers of the first utility.".(p 90). > 10% rate reduction (from 111196 rates) for resid, and small comm. From 111198 through the end of 2001. (p 32) Cumulative 20% rate reduction by 4/I/02 (costs are net of the competitively procured electricity and the costs of rate reduction bonds) i.e. does not insulate against market price increases. (p 28) IOU’s shall apply to the California Infrastructure and Economic Development, Bank (CIEDB) by 6/1/97 and secure the means to finance the CTC portion for res and smal! comm. secured by the income from these IOU customers. (p 33) These customer groups will continue to pay for these bonds until the bonds are paid off (p 78). Does not set a timeframe for CTC recovery. Defines rough categories of costs and requires a public hearing 6 months after costs are prepared. , Start Phase-in the latter of 1/1/2000 or 2 years after IOU’s begin phase-in. Phase-in completed by the latter of 12/31 2010 or 2 years after IOU’s end. Same as applies to IOU’s - no swiping an IOU’s or muni’s customer unless CTC is paid to former provider. (p 90) No rate reductions required for munis. Does not apply to Munis. IOU’s and munis are treated the same. Public Purpose Programs Local Control Cost Shifting General Fund Transfers " Sets out specific dollar amounts to be spent by the IOU’s in each of the four areas of: a) energy efficiency & DSM b) RD&D c) in-state operation and development of new & existing renewables, and d) low income programs. The money will be collected through a non- bypassable charge on local distribution service. The CEC will administer the moneys for IOU’s. Funding to begin 1/1/98 and run through end of 2001. Specific dollar amounts are stated for each utility & each program based on 1994 expenditure levels. Details era market-based allocation of the renewables funds will be developed by the CEC. (p 61-66) Creates a large number of conditions that the IOU’s must meet in order to ~ollect stranded costs. Establishes ’fire-walls’ between customer classes so that there is no cost shifting. (several locations) N/A Same four categories as IOU’s, except that renewables are focused exclusively on new renewables. * Overall dollar amount to be "not less than the lowest expenditure of the three largest electrical corporations on a percent of revenue basis". (The expenditure level appears to be approx. 2.5% of the 1994 revenues. CMUA is completing some analysis to determine the exact percentage as it applies to munis.) * No date is specified for beginning or ending the programs. * Muni~ get to choose amount to be placed in any/all of the categories. * Fundsand programs are to be locally administered. (p 67) States that "nothing in this division ..... shall affect preexisting ratemaking authority of a regulatory body era local publicly owned electric utility." (p 92) - But has two hooks that tie collecting CTC to direct access and joining the ISO. LS.._Q - Requires that Munisjoin ISO in order to collect stranded costs as allowed in the bill - "...no California electric corporation or local publicly-owned electric utility shall be authorized to collect any competitive transition charge authorized pursuant to this dix~ision ... unless it commits control of its transmission facilities to the Independent System Operator." (p 89) Direct Accest "let"-~ ne regulatory body does not authorize direct access as authorizedin this section, then the public owned electric utility shall not be eligible to recover the nonbypassable charge as provided in section 9603."(p 91) Does not specifically address cost shifting between customer classes for munis. "All city-owned electric utilities shall report oft the periodic bill the amount expected to be transferred to the general fund of the city on a no less than annual basis". (p 93) 2 ISO Governance ISO & Transmission Pricing Establishes a five member ISO Oversight Board to oversee the functions of the ISO and PX. Three members will be appointed by the Govenor from a list jointly provided by the CEC and CPUC. The other two members will be non-voting mebers appointed by the Assembly and Senate, TheOversight Board will determine the composition and term of the Governing Boards of the ISO and PX. A simple majority of the the Governing Board will consist of persons unaffiliated with G, T or D companies, (p 35) Requires IOU’s to place their transmission assets under the control of the ISO. There are many requirements and conditions relating to the ISO operation and structure. ’ Same as for the IOU’s. IOUs and munis should jointly advocate to FERC a transmission pricing methodology that inclu.des the following principles: (1) Utilityspecific access fees, as finally approved by FERC, reflecting that utility’s costs shall go into effect on the first day oflSO operation, (2) Within 2 years from the start of the ISO, the ISO shall recommend to FER.C a rate methodology determined by the ISO Governing Board (IGB). (a) If there is no IGB decision, the alternative dispute resolution method shall be used to determine rates. (b) If the alternative dispute resolution fails then the,default rate is a uniform regional access charge (> 230KV and an appropriate percentage of facilities below 230 KV) and a utility specific local access charge (all facilities not in regional charge). This shall be recommended upon termination of stranded cost recovery plan or no more than two years after initial operation of the ISO, whichever is later. (3) If the rate determined after two years is different than the rate in effect for the first :2 years then the difference will be trued-up within 3 years for IOUs and 5 years for munis. Munis are required to turn over control of their transmission facilities tO the ISO (if they want CTC collection as described in bill) TO: FROM: AGENDA DATE: SUBJECT: BUDGET 1996-98 City of Palo Alto City Manager’s Report HONORABLE CITY COUNCIL CITY MANAGER April 18, 1996 DEPARIWIENT: UTILITIES CMR:214:96 BUDGET ISSUE: Proposed Electric Fund Calaveras Reserve Policy This report requests that Council approve the proposed financial policy for the Calaveras Reserve to strengthen the Electric Utility’s competitive position under deregulation. The proposed policy substantially extends the life of the Calaveras Reserve. It establishes, a target level for the reserve which will .be reviewed annually and, if appropriate, revised with Council approval. The Reserve balance would be depleted gradually over an extended period, when the Electric Utility is predicted to face competition for customers. Using this reserve as a source of funds will reduce the need to raise the City’s retail electric rates in the future for the purpose of offsetting potential stranded costs associated with the Calaveras Hydroelectric Project. RECOMM:ENDATION Staffrecommends that Council approve the proposed Calaveras Reserve policy described in this report and reduce the Electric Fund Rate Stabilization Reserve by $15.9 million and transfer that amount to the Electric Fund Calaveras Reserve effective FY 1996-97. BACKGROUND In 1983, the City Council established the Calaveras Reserve in the Electric Fund to help defray a portion of the annual-debt service costs associated with the Calaveras Hydroelectric Project. Because of its high fixed costs, Calav.eras power is easily the most expensive resource in Palo Alto’s supply portfolio. Recent State and Federal developments to deregulate the electric industry have reinforced the need to extend the life of this reserve to help position Palo Alto’s Utility for an era of increasing competition. CM’R:214:96 Page 1 of 12 POLICY IMPLICATIONS The existing Calaveras policy does not provide for a target, and depletion of the Calaveras Reserve is presently anticipated by the year 2002. The proposed policy provides a target and extends the life of the reserve through approximately FY 2019-20. The proposed policy links the required balance in the reserve to an amount sufficient to cover the potential stranded costs associated with the Calaveras Project. In this manner, the need to raise rates in the future while trying to compete for customers is diminished. DISCUSSION Restructuring of the Electric Utility Industry On December 20, 1995, the California Public Utilities Commission (CPUC) issued its decision for restructuring California’s electric utility industry. The decision impacts how electricity is sold, priced, delivered and used. It proposes a timetable to open the electric utility industry to full competition by the year 2003, while allowing certain large commercial customers the ability to purchase power from alternative suppliers as early as 1998. The CPUC decision introduces a number of new terms and concepts. Exhibit A is a glossary of some of these terms. Also attached is an excellent pamphlet desgribing restructuring of the electric industry. The CPUC decision allows for investor-owned utilities (IOU’s) to recover 100 percent of their transition costs, which arise from the industry’s change from a regulated to a competitive environment. To pay for their above market generation costs, Pacific Gas and Electric Company (PG&E) and other California IOU’s plan to collect such stranded costs through a Competition Transition Charge (CTC) which will be an itemized charge on all customer bills. The CPUC goal is for utilities to recover transition costs before 2003 but no later than 2005. To strengthen their financial position in a competitive environment, many IOU’s plan to reduce operating costs, write-off assets, restructure and divest’the generation side of the business, accelerate depreciation, or sell generation facilities before 2005. In this manner, expensive generation assets may not cause their retail rates to rise to uncompetitive levels. Standard and Poors has acknowledged that the investor-owned utilities’ potential ability to "divest" or "write-off" high cost generation assets may lead to a cost advantage that municipal utilities wilt not be able to match (S&P, NY: CreditWire 4-21-94). CMR:214:96 Page 2 of 12 Although the CPUC does not have regulatory authority to apply its decision to municipal utilities, most municipal utilities, including Palo Alto, are considering providing comparable .choices for their customers, including direct access and unbundled rates and services, in a timeframe similar to that outlined for the investor-owned utilities. Given the anticipated arrival of open competition in the industry, it is prudent for municipal utilities, such as Palo Alto, to begin paying down their debt more rapidly, while there is some window of opportunity before full retail wheeling arrives. Stranded Costs ¯ As the electric industry transitions toward deregulation, many utilities are saddled with s0-called stranded costs-billions of dollars of sunk costs (debt) of generation or transmission resources with costs above market prices. These investments were made under the reasonable expectation that customers would continue to buy power from the local utility. However, under direct access, ratepayers may bypass the utility to purchase less expensive power on the open market. In this situation, the utility may find it difficult to recoup the costs of these "high’priced" assets, since revenues will drop. Furthermore, if competitors serve lucrative industrial customers, utilities may be left with primarily. residential customers to pay for those stranded costs.. Since the bulk of Palo Alto electric resources arise from wholesale contracts and are not projects built by the City, the electric utility’s exposure to stranded costs is not as great as most utilities, particularly the investor-owned utilities. Palo Alto resources such as Western, the Bonneville Power Administration, and Washington Water and Power have the potential to result instranded costs, but the probability of occurrence and the cost exposure is considered low at this time. Also, Palo Alto’s investment in the California- Oregon Transmission Project may result in stranded costs; and staff may present a recommendation next year to address this project. At this time, such cost contingencies are estimated to be within a range of probability and cost that they could be covered by the Electric Fund Rate Stabilization Reserve. However, the one generation resource in Palo Alto’s supply portfolio, which has the potential to result in significant stranded costs, is the Calaveras Project. Calaveras .Hydroelectric Project To meet its forecast for electrical power requirements .well beyond the year 2000, the City of Palo Alto entered a long-term agreement in 1982 to purchase power from the Calaveras Hydroelectric Project. The City’s decision to enter the Calaveras Project long- term agreement was made in. an era of double-digit inflation, when crude oil was $35/barrel and was forecast to reach $100/barrel by 1990. However, in 1986 world oil prices dropped substantially and today oil sells near $20/barrel. Because fossil fuel generated power and other cost efficient power resources on the open market are expected CMR:214:96 Page 3 of 12 to continue to cost less than Calaveras power for many years, Calaveras power, with its high fixed costs, presents a potential problem for the City. This Calaveras Reserve proposal aims to partially remedy this situation. : In 1983, the City Council established the Calaveras Reserve in the Electric Fund to "apply periodically to the financial obligations of the City arising from its Participation in the NCPA Calaveras Hydroelectric Project." The financial obligations arising from this project include a commitment by the City to pay its share of debt service costs, as well as annual operation and maintenance expenses of the hydro facility. The total project debt service obligation is approximately $1 billion through 2024 and is shared among nine cities. This financial liabili~ may change to some extent due to refinancing or restructuring of the debt, but the liability will likely remain through the year 2024 unless the project is sold outright to another party. Also, there is a contractual obligation referred to as a "step-up" provision for the project participants to assume additional debt, if a partner city should default on their debt service obligation. Palo Alto’s .actual share of the total debt service obligation (Exhibit B) is approximately $248 million, and current annual operation and maintenance expenses for the hydro facility are approximately $1.2 million. These costs make the cost of power from the Calaveras Project substantially more expensive than other power resources within Palo Alto’s supply portfolio. More importantly, Calaveras costs are much higher than the cost of power in the open market. Today the market price for similar wholesale power is approximately 2 cents to 3 cents per kilowatt-hour, whereas the total cost of Calaveras power is approximately 10 cents per kilowatt-hour. The wholesale power price in the open market represents the price at which competitors will probably offer to lure customers away from the Palo Alto .Electric Utility. When the total cost of Calaveras Power is higher than the market price for power, pressure exists to raise Palo Alto retail rates to cover the difference. However, raising rates in a competitive environment can result in customers bypassing the system, which can create more need to raise rates: By setting aside funds in the Calaveras Reserve to offset the "above market costs" of Calaveras, a future retail rate increase which may cause the overall price of power for sale by Palo Alto to be uncompetitive can be avoided. Calaveras Project Stranded Cost Calculation The potential stranded costs are primarily the fixed obligations for the Project that are above the cost to purchase equivalent power from the open market. This cost is a net calculation, which subtracts the expected market value of the Calaveras power delivered from the actual debt service obligation and other projected fixed and variable costs to CMR:214:96 Page 4 of 12 operate the hydroelectric facility. This approach takes into account the value of the project to the City by placing a market value on the expected output of the project and comparing that to what the City is actually obligated to pay. The difference represents potential stranded costs. If the amount is negative, (i.e. Calaveras costs less than comparable power on the open market), the difference may be referred to as a "stranded ¯ benefit". Stranded cost calculations are based on a number of variables and assumptions, as well as information that is fairly certain. For example, the. current debt service schedule is not an estimate but an existing financial obligation. On tlie other hand, the projected prices of power supplies on the open market for the next 28 years are highly uncertain. Staff is basing its market price estimates on a recent forecast performed by Henwood Energy Services, Inc. for the Northern California Power Agency. Such long-range forecasts can be highly subjective and inaccurate over time. Recognizing the volatility of stranded cost estimates, staff has developed alternative stranded cost projections (low, medium, medium-high, and high)’, which vary by forecast assumptions for power prices in the open market. The range of forecast assumptions under different scenarios is very broad, and the potential stranded cost estimate under the worst case scenario is considerably higher. The stranded cost estimates forCalifornia Investor-owned Utilities range from a negative $8 billion to $32 billion (CPUC Decision #95-12-063, page 125). For Palo Alto, preliminary staff calculations of Calaveras stranded costs indicate a range between a negative $38 million (low scenario) and $167 million (high scenario) in nominal dollars for the period 2003-2020. The wide variance in stranded" cost estimates only demonstrates the need for more evaluation and questioning of the underlying assumptions. However, even if the forecast proves totally in error and the City never incurs stranded costs, theCalaveras debt service is a real obligation that regardless, requires funding through rates or reserves. On this basis alone, it is prudent to plan to extend the life of the Calaveras Reserve: The estimate for Calaveras stranded costs, on which the Utility’s proposal is based, is approximately $42.1 million between the period 2003 and 2020. The current forecast. indicates that after 2020 the Calaveras Project will provide stranded benefits and, therefore, funds do not need-to be set aside. $42.1 million in nominal dollars translates to a net present value of $31.6 million in 2003 dollars and is based on .the staff’s medium scenario for stranded ’costs. Therefore, the recommended Calaveras Reserve target balance at the end of FY 2002-03 is $31.6 million. The difference of $10.5 million ($42.1 million-S31.6 million) represents estimated future interest earnings .on the CMR:214:96 Page 5 of 12 Calaveras Reserve, which accrue on the reserve balance at approximately 6 percent annually. This scenario relies on a median forecast of market prices that escalate approximately 3.3 percent annually, in combination with other variables such as the extent of surplus capacity in the Northwest. Consistent with the original intent for establishing the Calaveras Reserve in 1983, this reserve proposal funds approximately 26 percent of the Calaveras debt service obligation between 2003 and 2020, which diminishes the need to raise rates for that purpose. Although the debt service obligation continues to 2024, after 2020 the Calaveras Project is currently projected to cost less than the price of power on the open market and payment of the project’s debt service may be accommodated without raising rates. Besides helping to position the Electric Utility for competition, establishing a reserve specifically to cover a large portion of annual debt service obligations will be viewed favorably by the rating agencies and bond market. This may help maintain or improve favorable bond ratings and lower interest costs to the City on future revenue bond financings. Likely beneficiaries include possible Storm Drain and Wastewater Treatment revenue bond fmancings. It should be noted that the-proposed Calaveras Reserve policy, as described in the attached memorandum to the Utilities Advisory Commission, has been revised since it was issued on March 6, 1996. The assumptions related to the ot~tput of the hydro facility have been revised, which changed the stranded cost estimates. This staff report to the Council contains the updated information. Proposed Calaveras Reserve Policy The proposed policy is intended to lessen the need to raise retail rates, when the Palo Alto Electric Utility is expected to compete with alternative suppliers of electricity. By accelerating the collection of above market costs associated with the Calaveras Project, Palo Alto future ratepayers and the, City of Palo Alto are favorably affected.. The following components are recommended as guidelines for the Calaveras Reserve policy: 1. Maintain a reserve sufficient to offset potential stranded costs and committed to repayment of a significant portion of the principal and interest for Calaveras debt service through 2024. 2. Establish an initial Calaveras Reserve balance of $31.6 million as the target level to be attained at the end of FY 2002-03. The adequacy of this target level will be evaluated during FY96-97 and annually.thereafter as noted in (4.) below. CMR:214:96 Page 6 of 12