ML17297A654

Annual Financial Rept 1980

ML17297A654
Person / Time
Site:	Palo Verde
Issue date:	08/05/1981
From:	SALT RIVER PROJECT
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Background===

Salt River Project, named for the The District, a political subdivision major river that supplies water to the of Arizona, operates under contracts Phoenix metropolitan area, has played with the United States of America and a leading role in the growth of the Salt provides electricity to residential, River Valley, providing water and commercial, industrial and agricultural power to area residents. The Project is power users in a 2,900.square mile comprised of two organizations the service area in parts of Maricopa, Gila Salt River Valley Water Users and Pinal counties.

Association (the Association) and the Following the long. standing Salt River Project Agricultural reclamation principle, SRP uses a Improvement and Power District (the portion of its electric revenues to help District). support its water operations. This The Association is a private Arizona practice helps keep water delivery corporation. It participates in the charges to farmers, cities and management of the 13,000.square. homeowners at reasonable levels. And mile watersheds of the Salt and Verde concurrently, SRP maintains electric rivers, in cooperation with the U.S. rates which are competitive with other Forest Service. The Association utilities in the area.

administers water rights of the Project's 250,000~ere area and operates and maintains the irrigation transmission system which carries water to agricultural, municipal, industrial and residential users.

Ptj BUSHER Contents 3 4

1 Highlights Letter From Management Efficiently providing power SRP Communications Public Affairs Department 6

to the people who need it EDITOR Howard C. Alexander 8 1980 was a year of water contrasts DESIGN 12 The human touch: Harvey Oblander people keep us working PHOTOGRAPHY 15 Financial commentary Ed Toliver 17 Combined financial statements Chet Snellback Lauren Mildenberg 21 Notes to combined financial statements Harvey Oblander 24 Statistical review PRODUCTION 26 Board members Communications Services Division 28 Council members Sait Rior Project is an Equal Opportunity Emptoyer Cover photo: Chet Snellback Maintenance on large transmission lines receiues a top priority at SRP.

Highlights For the Twelve Months Ended April 30, 1981 and 1980 and the year ended December 31, 1979 (oooo)

Fiscal Year 1981 SOURCES Dollars Percent Residential . $ 2]2,470 39.4X Commercial and Industrial 182,632 33.8 Sales for Resale 112,630 20.9 Agricultural Pumping, Street and Highway Lighting, and Public Authorities . 23,212 4.3 Water and Irrigation Revenues . 5,312 1.0 Other . 3413 .6 TOTAL . >539 659 100.0X USES Fuel Used for Generation . ~]39,))2 25.8X Purchased Power . 20,852 3.9 Other Operating Expenses 75,175 13.9 Taxes and Tax Equivalents . 58,134 10.8 Depreciation and Amortization . 56,123 10.4 Maintenance ...................... 50,927 9.4 Net Interest for Indebtedness . 47,460 8.8 Miscellaneous Deductions (Income) (1,644) (3)

Reinvested . 93 530 17.3 TOTAL . 4539 669 100.0X WATER OPERATIONS 1980 1979 Assessed water accounts . 177,171 174,603 Water runoff (acre. feet)" . 2,879,637 2,402,641 Water in storage, Dec. 3'I (acre feet) 1,480,332 1,290,97]

Total water deliveries (acre-feet) 1,446,277 1338,008 POWER OPERATIONS 1981 ]980 1979 Number of Power Customers . 330,251 313,135 309,702 Average Annual Use Per Residential Customer (KWH)......... 12,310 12,557 13,038 Average Annual KWH Revenue Per Residential Customer (Cents) 5.78 5.28 5.07 Energy generated, purchased, interchanged and wheeled (KWH) 13,292,600,000 12,054,266,000 11,496,850,000 Peak load for Project customers (KW) 2,057,000 1,911,000 1,911,000 FINANCIALDATA Electric Revenues ............ S 534,357 ~ 444,887 ~ 413;066 Water and irrigation Revenues . 5,312 4,696 4,723 Total Operating Revenues . S 539,669 > 449,583 S 417,789 Taxes and Tax Equivalents 58,134 45,199 42,859 Total Operating Expenses . 4 400,323 324,507 291,610 Net Revenues . 93,530 93,587 100,435 Plant Investment, Gross S2,843,247 ~2,493,501 ~2,355,783 Long.Term Debt $ 2,209,276 ~2,0]9,998 ~],9]4,080

'Statistics on mater are computed on a calendar year basis "Based on US.GS. prooisional records and subject to adjustments

John R. Lassen Vice President

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I t 4 ~ i, Karl F. Abel A President Jack P/ister A General Manager

Letter from management It was an active and successful year We have decided to sell title to property as collateral for money for Salt River Project. 225,000 kilowatts of our ownership in needed to build the project and hence Despite tough economics and high the Palo Verde Nuclear Generating their vote should be commensurate inflation, bond ratings remained stable Station under construction west of with their risk. Today, each acre still at "Aa" and "A+" and debt service Phoenix. Our decision to sell was has a lien of about S1,000.

coverage closed at 1.74, thanks in difficult to make due to our continued Finally, the credit for our successful part to some innovative financing confidence in nuclear power and operations should go to our tactics. We were among the first particularly Palo Verde. However, employees. Their intelligence and skills municipal type utilities in the nation to customer electric use projections we make it possible to provide water and issue tax.exempt commercial paper made prior to the 1974 Arab oil power with the tradition of excellence when our board authorized sale of up embargo predicted more growth than we have established over the years.

to $225 million. actually occurred. Without a sale, Through employees'bility to pull For the overall financial picture, we would have had a large amount of together and operate as a team, we operating revenues increased 20.0 costly surplus generating capacity. We will continue to achieve our primary percent from last year, but expenses discuss in more depth the reasons for goals-providing reliable supplies of increased by 23.4 percent. We raised the decision to sell in the "Power" water and power at reasonable prices.

electric rates by an average of 12.8 section of this report.

percent in April. In the water area, we supported the We continued to move away from passage of the new Arizona expensive foreign oil and towards Groundwater Management Act. We cheaper, efficient coal for most of our continue to work with shareholders energy production. Two new coal fired and our water users to help protect units-one in northeast Arizona and the their groundwater rights and make other in northwest Colorado-began sure they have a guaranteed supply of commercial operation during the year. groundwater.

As a result 75.8 percent of the We hired two consulting panels to electricity used by our customers was study dam safety, as a result of federal produced by coal. And that's 6.8 studies that indicate a potential three-percent more than last year. fold increase in the amount of water To help develop energy sources for that might enter our reservoirs as the future, we began three solar runoff during violent storms. At the projects. Two of those projects, one same time we are watching with residential and one industrial, will test interest the separate G.S. Bureau of the feasibility of solar air conditioning Reclamation safety of dams studies of in a desert climate; the third runs the Roosevelt and Stewart Mountain dams.

motor of a small deep well pump. We Near the end of the fiscal year, we also continued work on a small learned that the Q.S. Supreme Court hydroelectric generating station upheld by a 5 to 4 vote the method of located on the South Consolidated electing the'District's Board of Canal. Directors. That method, provided under state law, was established on the basis that landowners living within the boundaries of the Salt River Valley Water Users'ssociation pledged their

Efficiently providing power to the people who need it When Horace Greeley told his expenses for part of a generating "aspiring young men" in 1846 to station they wouldn't need for several "turn your face to the great West, and years, our Board of Directors there build up a home and fortune," approved a management he had no idea so many would follow recommendation in April 1981 to sell his advice. one. fourth of SRP's 29.1 percent share Many people did come and "built in Palo Verde. The buyer of that up" their homes, and they continue to portion of Palo Verde, pending do so today. execution of an agreement and certain Providing dependable electricity to regulatory approvals, is the Southern a rapidly increasing population is one California Public Power Authority. The of the most challenging tasks facing sale is expected to be completed all southwestern utilities. between January and April, 1982. Our Because planning for growth existing resources, coupled with our requires commitment decisions 10 or remaining share of Palo Verde, will be more years before large generating able to meet current growth stations begin production, we at Salt projections through 1990.

River Project in 198081 found ourselves in what might appear to be Coal the economical a paradox. While two new coal. fired generating units were beginning southwestern fuel commercial operation, we were The second unit of the Coronado deciding whether to sell a percentage Generating Station near St. Johns, of our ownership in the Palo Verde Arizona, began commercial operation Nuclear Generating Station being on October 31, 1980, and the second constructed 50 miles west of Phoenix. unit of Craig Generating Station at This apparent paradox resulted from Craig, Colorado, followed on January Sixty.one meter readers read the more the decade. plus advance planning 1, 1981. Together, the two units add than 320,000 residential meters each period required to bring generating 366,000 kilowatts (kw) to our month in SRP's electric serUice terntonj. stations into service. generating capacity.

During the 1960s and early 1970s, This past year coal. fired generation when oil was readily available and supplied 75.8 percent of the electricity inflation was much lower than it is our customers used. By relying on this today, we projected a growth rate for comparatively inexpensive energy peak electric demand of 7.to.8 source, we were able to keep fuel percent a year through the 1980s. We costs relatively stable. The fuel began construction of generating units adjustment charge to customers to meet the projected growth. But remained constant during the year at then we felt the impact of the Arab oil the July, 1979, level.

embargo of 1974 and the economic During 1980, work began on a slump that followed. Our growth rate previously planned improvement to slowed to 2.to-3 percent a year. And Coronado's coal handling system. This conservation, which we actively modified system will further increase promote, was foremost in many station efficiency by mixing coal from people's minds. supplying mines for a stable blend of We soon realized that part of the fuel. Since the qualily of the coal power from the Palo Verde station burned affects overall station would not be needed until well after operation, the uniform mix will help 1990, instead of in the mid.1980s as assure we get the most efficient use of had been previously projected. Rather the coal we bum.

than saddle present electric customers The residue of burned coal called with construction and interest "fly ash" was put to beneficial use.

During the year, we sold more than

$ 590,000 worth to a company that' using it as a strengthening agent in concrete.

Efficiently providing power to the people who need it The Coronado station uses a unique scrubber system to remove 3, sulfur dioxide from stack exhaust gases. SRP and several other western utilities helped develop the prototype of this system. Coronado is the first commercial application of this design, and the installation received the 1980 Environmental Protection Award from Power Magazine. Unlike conventional

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scrubbers, this one uses a horizontal q tunnel to "wash" stack gases with a limestone and water solution. Sulfur is )( /

removed in the process, protecting the environment.

Palo Verde construction 58% complete overall By April 30, 1981, Gnit 1 of the Palo Verde Nuclear Generating Station was 86 percent complete. It is scheduled to begin commercial operation in 1983. Gnits 2 and 3 were /'61,267 58 percent and 19 percent complete, respectively. Overall, construction was 58 percent complete.

Although the proposed sale of to 41,778 barrels during the SRP linemen participate in maintenance 225,000 kw of the station's capacity comparable period. training on 500.kilouolt lines.

was approved by our board in April Natural gas displaced more than 1981, we will still own 670,000 kw of 101,200 barrels of diesel and another the station's capacity when it begins 266,900 barrels of residual in 1980.

producing power. Thus, we continue 81. We burned gas instead of oil at Customer Growth to support nuclear power as a our Agua Fria and Kyrene generating valuable part of this nation's energy stations.

mix. Nuclear energy will provide 16.7 600,000 percent of our customers'eeds when Transmission system all three units are completed in 1986.

continues to grow 500.000 Natural gas availability In March 1981 we awarded a $ 7.0 400,000 million contract for labor costs to build reduces oil usage a 75 mile long power line. The 500 kv 300,000 Because of improved natural gas line will connect the Palo Verde supplies, we burned 57 percent more Nuclear Generating Station to our gas last year than in 197940. As a 200,000 Kyrene Generating Station in Tempe.

result, we saved customers more than Completion of the line is scheduled for

$ 12.9 million in fuel oil costs. August 1982. 100.000 Since gas was available, we burned We are project manager for the 91 percent less fuel oil in 197980. line. Other participants are Arizona Residual oil use totaled only 102,391 Public Service Co., EI Paso Electric 1979 1980 1981 1985 2000 barrels last year compared with Co., and Public Service Company of 1,293,145 barrels during the previous New Mexico. For the tioetoe months ended Apnt 30, 12 months. The amount of diesel oil 2000, 1985, 1981 and 1980 and year ended December 31, 1979.

burned by generators dropped from 1985 and 2000 projected

Efficiently providing power to the people who need it Two 230.kv lines one on the west Street and security lighting became side of the Valley and the other on the a new administrative division during east were in various stages of the year. We organized the division for planning. One line will connect the better customer service to both Agua Fria Generating Station in Peoria individuals and municipalities.

with the Alexander Substation in We used a technique known as northwest Phoenix. The line is targeted "barehanding" to perform to go into service in June 1983. maintenance on high voltage Preliminary studies are under way transmission lines. By working in for the Papago Buttes.Pinnacle Peak insulated buckets, our linemen safely Transmission Line. Our studies have can make necessary repairs to lines indicated it will be needed to serve the carrying as much as 500,000 volts east Valley by 1988. without cutting off the power. One of the benefits of this technique is that Nore customers by keeping the power flowing from mean more power our coal fired generating stations we do not have to substitute oil fired By April 30, 1981, we were serving generation from the Valley to meet 330,251 customers, compared to customers'eeds. Savings to 313,135 served at the end of the last customers is the result.

fiscal year. Another savings for customers Customer growth combined with $ 1.45 million worth during the the hottest July in Arizona record. summer billing period (May-keeping history pushed our customers'eak October)-resulted from using our demand above two million kw for pumped storage hydroelectric the first time. At five p.m. on July 28, generating units at two dams on the 1980, customers'emand peaked at Salt River.

SRP agreed to sell 25 percent of its 2,057,000 kw of power. That was Pumped storage units act as both interest in lhe Palo Verde nuclear 146,000 kw more than 1979's peak. pumps and generators. During Generating Station under construction With growth comes new power periods of peak demand, water passes est of Phoenix. sources. Work was nearly completed through the unit and spins a turbine on a small hydroelectric generating which powers a generator. During facility. Located on the South periods of low demand, electricity Consolidated Canal near Mesa, the from coal. fired generators one of our station will add 1,400 kw to our least expensive sources powers the system. It has the added advantage of turbines which serve as pumps and being most effective during the hottest push water back up to a higher months when the most power is reservoir. There it is stored until the needed. The Q.S. Department of next time electricity demand is great.

Energy supplied grant money to assist We entered the 1981-82 fiscal year in the station's construction. faced with the same basic challenge that of meeting the need for power in the most cost effective manner.

Through planning, research and development, and a healthy understanding and appreciation of an ever. changing economy and technology, we will continue meeting that need.

Efficiently providing power to the people who need it Ouerhauls help keep turbinegenerators running at peak efficiency at generating stations such as Coronado near St.

Johns, Arizona.

Project Energy Sources Year Ending 1 2 l4sc.

Apnl 30, 1979 Hydro Gas 1 3.0X 7.0 Oil 11.0 Coal 66.0 tfucfear Purch.

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1980 12.0 7.5 7.0 69,0 ~ 4,5 1981 1 1 A 10.7 0,5 7M - 1.6 1982 10.3 7,7 OA 81.6 1986 8.4 4.2 0.9 69.8 16.7 I Includes hydro purchases.

2 Includes WAPA lYauajo Entitlement and uial generation fmm coal uni Ls under carzslrudion.

Salt River Project Electric Service Area Salt River Project Electric Service Area hyfrrn Qa 3 4

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PhOOhlx 0 MlAMI 0 APACHEJCT.

C7 Electric Service Area Served Exclusively by Salt River Project Do Dr 0

SUPERIOR Salt River Project Prov~des Full Power FLORENCEJCT.

Requirements of Arizona Public Service for Resale. project Makes Direct Sales to Customers for All Mining Loads A Peona 1, Granite Reef Dam Salt River project provides Full power 8, Glendale 2 Stewart M! Dam HAYDEN Requirements of Arizona Public Service C. Scottsdale 3, Mormon Flat Dam for Resale D Tempo 4, Horse Mesa Dam E, Mesa 6, Roosevelt Dam Electric Service Areas Not Served F Gilbert 6 Bartlett Dam by Salt River project G Chandler 7. Horseshoe Dam

1980 was a year of water contrasts Water statistics are computed on a totaled more than $ 2.0 million, of calendar year basis. Water reuenues which $ 1.0 million was spent in 1980 and operating expenses are computed to repair that dam's spillway. Repairs on a fiscal year basis. to all other spillways, channels and powerhouses were completed by It was the fourth wettest year in year's end.

history. February was the third wettest Granite Reefs concrete retaining month recorded since 1913. And wall was damaged severely by the between January and July, runoff was more than 300 percent of normal. heavy runoff. SRP civil engineers The storm conditions which caused designed and inspected a reinforced floods in February changed rapidly. concrete retaining wall which was Runoff declined throughout the year constructed by contract to protect the and as 1981 approached, runoff embankment against future erosion.

forecasts for the first five months were On the upstream side of the diversion dam, crews manned the "Katy only about one. tenth as much as Pickrell" dredge and removed more actually occurred for the same period in 1980. At the same time, forecasts than 12,500 cubic yards of for the year 1981 were for runoff one- accumulated silt.

fourth of the normal 68.year average.

At the beginning of 1980, reservoirs Expanded technology were 75.7 percent full, containing helps management 1,563,309 acre feet (af). By May 20, Modem science benefited water they reached their peak storage, operations during both the storm and 2,047,626 af, or 99.2 percent of normal runoff season.

capacity. By the end of December, We made extensive use of an Army contents had declined to 1,480,332 af Corps of Engineers computer or 71.7 percent of capacity. program to simulate reservoir Agricultural specialists assist Valley Lakes on the Salt and Verde rivers farmers with special irrigation and water operations based on anticipated use technigues. received 2,879,637 af of runoff in runoff. These programs assist 1980, an 18.9 percent increase over management to make decisions on 1979. Largely because of a warm rain. release amounts and times.

on heavysnow situation in February, Management received more runoff for the year was 246 percent of information faster than ever before the 68 year average. Runoff for during the year from an additional 20 February was 917 percent of average; satellite. linked gauging stations on the in December, the situation was 13,000 square mile watershed. The different runoff was only 41 percent stations measure river levels to of average. indicate how much runoff to expect.

Because of flood sized inflows early The addition of sophisticated in the year, 1,979,679 af of water had weather radar helped to predict the to be released from the dams to flow intensity of winter storms. Snow water down the Salt River through Phoenix. content and precipitation gauges That amounted to nearly a two.year assisted in relaying data during the supply and close to the capacity of all runoff season.

six reservoirs.

Consultants examine Most storm damages dams for safety to facilities repaired As part of the Safety of Dams Act, The rushing waters of February left the federal government developed new S3.5 million in damages to our figures for what it calls an "inflow facilities. Damages occurred to design flood," or the highest projected spillways at all six dams on the Salt volume of water that could and Verde rivers and to the Granite conceivably enter the reservoirs in the Reef Diversion Dam which diverts form of runoff over a short time.

water out of the river and into the SRP Those figures show possible runoff to canal system. be as much as three times greater Damages to Roosevelt Dam alone than previously anticipated.

Consequently, safety modifications to the dams have become a requirement.

1980 was a year of water contrasts We retained two consulting teams to study the safety of SRP operated dams. One was hired in June to concentrate on the structural integrity of Stewart Mountain Dam and what might happen if the water level of Saguaro Lake reached the top of the dam's parapet, or top of the dam. The study was near completion at year' end. Results were being forwarded to .y" 7 the U.S. Bureau of Reclamation 5 (USBR), because the United States IIIIllllll holds title to the dams SRP operates, and the Bureau is the federal agency responsible for safety of its dams.

Another consulting team was hired in November to examine possible modifications to Roosevelt'Dam, including raising its height to increase dam safety and store more runoff.

That team's report is expected by mid.

year 1981.

Both consultants'tudies are in addition to the Central Arizona Water Control Study that both USBR and the U.S. Army Corps of Engineers are conducting. That study is examining Orme Dam, plus alternatives for flood Those lands used 64,505 af in 1979. Bartlett Dam's domnstream facilities

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control and regulatory storage for the Contract deliveries, which include mere repain.d folloming the Febrtrary Central Arizona Project. We are city users on nonmember lands, 1980 storms.

following closely all phases of this amounted to 192,909 af last year an important study. increase of 14 percent from 1979 when that category of deliveries totaled Water deliveries increase 166,606 af. The water taken is Land Gse 9.3% from 1979 replaced by the cities from other sources, usually city wells.

We delivered 1.2 million af of water Most of the water delivered 94.5 240.000 Acres to municipal, agricultural and industrial percent came from reservoirs. Only customers in 1980, compared to 1.1 65,648 af had to be pumped from the 200.000 million af in 1979. The increased use Project's 247 wells, and most of that was the result of bountiful supplies was pumped directly into city 160.000 and allocation by the Board of pipelines. As a result of the decreased Governors of an additional two af of groundwater pumping in the last three 120.000 water per acre. The board took this years, the Valley's water table has risen action in June to help bring down approximately 35 feet since 1977. 80,000 reservoir levels. Urbanized land within SRP Non agricultural uses of water boundaries totaled 132,450 acres at 40.000 increased to 362,758 af in 1980, year's end, or 55.6 percent of the compared to 334,310 af in 1979. Of Project's 238,221 assessed acres.

that total, cities received 247,190 af, Agricultural lands decreased by an increase of 11.3 percent. Parks, 3,451.8 acres during the year, to 1978 1979 1980 1985 2000 schools, churches and residential 105,771 acres, or 44.4 percent of the property received 115,568 af, Project area.

compared to 112,212 af in 1979. But in spite of conversions to urban Agricultural users received 579,650 use, total water use remains about the 1985 and 2000 projected af; use in 1979 was 535,047 af. same although it increases slightly in Decreed lands, including Indian years such as 1980 when there is reservations, used 67,762 af in 1980.

1980 was a year of water contrasts 10 excess water. A fully urbanized SRP the capacity of existing drain

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area would probably require about the structures at the end of the Grand same amount of water as is used Canal. We also improved the channel today. that carries storm runoff into the New River near 103rd Avenue.

7 pgZ Water charges increased Cost of the SRP work performed In December, the Board of during the dryups was about Governors approved a 1981 water S679,000.

assessment of $ 13.50 per acre, an Water rights negotiated increase of 12.5 percent from 1980's assessment of S12.00 per acre. The SRP, the Arizona Department of board also allocated an additional acre Water Resources and the U.S. Forest foot of stored and developed water for Service formed a committee in 1980 S6.75, also 12.5 percent more than to examine water rights disputes. One 1980's charge of $ 6.00 per acre foot. of the first projects the committee The increase in charges is the tackled was an interim settlement to a eighth since 1972 when the water rights violation that had cost our assessment was S4.25 an acre. shareholders up to 5,000 af of water a Assessments help pay operating costs year.

of the Salt River Valley Water and are applied equally to Gsers'ssociation Groundwater all lands within SRP.

The board also raised delivery fees Management Act passed for irrigation customers by 5.1 percent, Depleting groundwater supplies from S21.84 per account plus 15 always has been a concern to SRP.

cents per acre, to $ 22.96 per account Groundwater has never been relied plus 16 cents per acre. As a result, the upon as a prime source of water for Gauging stations oivned by the US. cost for irrigating a typical one. fifth the Valley; rather, it has served to Geological Survey provide valuable supplement the surface water stored in utter depth and speed information to acre lot rose from $ 23.07 to S25.69.

The new figure includes $ 2.70 for the the reservoirs. On the average, about SRP by satellite. Such information is one third of the water SRP delivers particularly useful during the runoff assessment and $ 22.99 for the delivery season. charge. comes from wells, with the remainder from lakes. However, because of wet Canal dryups allow years since 1978, surface water provided about 94 percent of the for construction water the Project delivered.

and maintenance Gov. Bruce Babbitt, on June 12, 1980, signed into law the Groundwater Annual canal dryups held between Management Act, which is intended to mid October and mid.December bring overdrafting of groundwater allowed SRP to line and maintain parts supplies under control by the year of the 131-mile canal system. Local 2025. The act also is designed to governments took advantage of the bring groundwater use into balance diyups.to modify and build bridges with groundwater recharge, so that a over the canals. condition known as "safe yield" will Workers applied concrete-like lining exist.

to a 3.8 mile section of the Eastern For the future, SRP will work with Canal and a 1.1 mile stretch of the the state to ensure our compliance Arizona Canal to reduce water losses with the new groundwater act. In 1980 through seepage. Nearly 69 miles of SRP co.sponso'red two symposiums in the major canals have been lined to date.

Scottsdale on groundwater and wells.

While canals were diy, we modified canal structures and a contractor began construction of a 1,400 kw hydroelectric generating station valued at S2.4 million on the South Consolidated Canal in northeast Mesa.

The station began producing electricity in 1981.82.

In addition, modifications increased

1980 was a year of water contrasts Rooseoett Lake, one of six reserooirs in SRP's system, offers recreational as mell as mater storage bene fits.

Domestic Water Deliveries X of 1980 1979 Change Scottsdafe 5,085,93 2.749.25 85%

Glendale 13.565,22 11,959.78 13%

Peoria 2,269,57 1.875,92 21 X Gilbert 1,862,31 1.868,31 ..003%

Tenlpe 28.614,58 24.442,66 ivteso 20.60?.90 3X 17'0.090A4 Chandler 3.411.53 2A83,94 37K Phoenix 171.77fL07 156,627.45

.097'otal 247,190.11 222,097.75 11%

Allnnmbers are ln acrofeee except p<'rcents of change.

Salt River Project Watershed and irrigated Area ASH FORK ~ ~ FLAGSTAFF CC PRESCO~O <<3 1Granite Roof Oam 2 Stewart Mt Oam S PRINGERVILLE Salt River Protect lrngated Area 3 Mormon Flat Oam PAYSQt4 4 Horse Mesa Oam 5 Roosevelt Oam 13,000 Sq, Mile Protect Watershed 6 Bartlett Dam 7Horseshoo Dam A, Peoria 8 Glendale C Scottsdale 0, Tempo E, Mesa A

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F. Gilbert PH QX APACHE JCT.

G Chandler

The human touch:

people keep us working 12 While SRP's primary objective is to given for research to Western Energy assure our shareholders and Supply and Transmission Associates, customers a reliable supply of water a group of 20 utilities in the southwest.

and power at reasonable costs, we do Other RGD projects included load more than just that as a company, management (described later in this groups of employees and individuals. section), a coal blending test at the We take pride in our position of Coronado Generating Station, and leadership in our industry and in the tests on new materials for insulators in efforts of our employees on and off our electric distribution system. We the job. helped develop a computer model to In 1980-81 we accomplished much assist in future electric load forecasts.

in the way of service, research and The model can examine energy uses production. of individual customers and by studying various conservation We did research techniques of those customers, can and development predict what energy use will be for the entire service area.

In Arizona, where the sun is so We also tested three heat pump much a part of our everyday lives, it is water heaters in customers'omes to only natural to investigate its use to determine their energy effectiveness.

help lessen this country's dependence We have found that heat pumps use on expensive foreign oil. During the only one. third as much energy as year we began installation and testing conventional water heaters.

of two Rankine engine solar. powered air conditioning systems. A 50 ton We managed energy system is located on one of our large We also conducted research buildings near our administrative headquarters. The other concerning ways to help consumers Employees such as Walt Goodman and a three ton system save money by conserving energy.

Denise Mullins donaie many hours each is on a private home in One method is called "load year as members of the SRP nearby Chandler. We hope the tests, management." Simply, "load to help make our which are being conducted with help Boosters'ssociation communily a better place to live. Above, management" helps balance the from various private businesses and demand for electricity throughout the Walt and Denise spend time uiilh public agencies, will speed the students at the Gompers Rehabilitation day.

commercial availability of such solar This balancing is achieved by Institute in Phoenix.

energy equipment. reducing the maximum amount of We also were involved as a electricity a customer uses at any one participant in four other solar research time or "peak demand" and projects. They included the production spreading the use out to other times.

of direct current through the use of By reducing peak demand, less oil and photovoltaics at two projects, a solar other expensive generating fuels have water heater assessment study with to be burned.

Arizona State Gniversity and a passive We are experimenting with different solar study in one of the photovoltaics types of load management programs.

projects. We also conducted a In one, we control the customer' separate ice storage project at a solar.

energy use by cycling air conditioners, powered home in a nearby suburban water heaters and swimming pool community.

We spent $ 1.85 million for all pumps via computer for brief time periods. Nine out of 10 participants research and development during the say our control has not been year. Of that, $ 1.26 million was noticeable or disturbed them and their contributed to the Electric Power lifestyle.

Research Institute in Palo Alto, In the other type of load California, to assist in work to benefit management program, we began all electric utilities. Also, $ 18,000 was offering experimental timeaf4ay rate programs to encourage customers to shift their major energy use from normally high-use times to low.use times. These programs charge more

13 The human touch: people keep us working per kilowatt hour for electricity used Public Power Association for the best reinforce our commitment to equal during heavy.use times, when it costs safety record among the group of opportunity.

more to generate power. To the largest utility members. SRP had 20 The consent decree, which is customer, the economic value of these percent fewer injuries than the national consistent with two Federal Executive programs are instantly noticeable. average for electric utilities. Orders, sets goals for annual increases Average savings for participants during in the hiring of women in 29 separate the summer of 1980, compared to We expanded facilities non.traditional job groups. Goals vary regular residential rates, were about

~23 a month. In the winter of 1980-81, for better service by job, depending on the number of women working in that job in average savings for the customers was Maintaining service to customers Maricopa County or the relevant job about S5 a month. means adding facilities and people. market. The decree also reinforces our We promoted energy conservation. We began construction on a 54,000 commitment to increase recruitment Our Power Saver Service advisors square foot addition to our efforts to find qualified women visited more than 5,800 homes and administrative headquarters. The extra employees, thereby expanding job nearly 500 business and apartment office space will house additional opportunities for women at SRP.

complexes to perform energy audits employees needed to better serve the and offer cost-cutting tips. Those nearly 300,000 new customers. we We develop inspections have been expanded to expect to add during the next 20 provide solar water heating advice years. The addition will cost S3.6 our management and more detailed, computerized million. We also opened a new During the year we offered two new conservation data. Customers are told business office in northwest Phoenix in management training programs to how long it will take for their June 1980 to better serve the more better prepare our employees for investment in energy saving materials, than 65,000 customers we have in future leadership roles. Two hundred such as insulation, weatherstripping or that vicinity. twenty. five employees completed shade screens, to pay for itself through supervisory training. We also started lower energy costs. We are an equal an executive resource planning Customers purchased 333 opportunity employer program to plan future needs of key top management positions. The goal weatherstripping kits, 375 water heater jackets, 623 attic insulation jobs and Affirmative action continues to be a is to prepare selected employees to 573 shade screens from SRP. Surveys prominent part of our management assume those positions and to begin indicate at least as many conservation. strategy. Because of that commitment, training to help them strengthen their we ensure equal employment capabilities. This type of executive type purchases were made from other sources. opportunity to all employees in all planning common in industry but jobs. To help meet our affirmative relatively new to public utilities We promoted safety action goals during the year, we increased recruiting efforts, revised establishes an orderly development As delivery agent for most of the plan through a pool of qualified selection procedures and took part in candidates for promotion into top water used in the Salt River Valley, we an apprenticeship international fair for also recognize the importance of management. It's part of our "grow women sponsored by the Arizona our own" philosophy.

promoting water safety among Department of Economic Security. In children.

During the year, public affairs our three. year apprenticeship program, Our employees 53 of the 132 participants were representatives talked about water members of minority groups. Two take the extra step safety with more than 20,000 were women. Individual employees made elementary school students in 100 In 1980 we entered into a consent contributions to the community.

schools. Since 1967, we have decree, approved by the U.S. District SRP people gave their money.

presented the "Salt River Pete Water Court, which provides specific 'Through payroll deductions, Safety Program" to more than commitments to female employees employees throughout the state 300,000 children. and job applicants. The decree contributed more than S163,000 to For safety on the job, we earned a represented the settlement of a class various charities. As an organization, first-place award from the American action lawsuit alleging discrimination SRP contributed more than ~186,000 on the basis of sex. to United Way, Junior Achievement, In the suit, we denied we had continued discriminated against women.

However, we agreed to expand affirmative action programs to

The human touch: people keep us working League of Women Voters, St. Joseph' Phoenix, we administered an on-the-Hospital, YMCA, Boys and Girls Clubs, job career opportunities program for Urban League, March of Dimes, Big high school students.

Brothers and Sisters and others. To become even more responsive Our people gave their time. They to the needs of the Navajo Indian serve on city councils and school Nation on whose land the Navajo boards in Glendale, St. Johns and Generating Station is built-we hired a Page. One employee is chief of a specialist in communications and volunteer fire department; another is a sociology. Through direct daily state legislator; and several are reserve contact, he is working to improve po! ice oHicers. understanding between the Indian's One executive is a member of the and Anglo's cultures.

board of directors for the Better We conducted extensive public Business Bureau and the Electric communications programs, to help League of Arizona. Another is develop better understanding on such metropolitan chairman of the National subjects as energy, electric safety, Alliance of Business and a board water safety and flood control. Our member of the Phoenix Chamber of 130.member speakers bureau made Commerce. more than 600 presentations to Valley Two executives are board members groups.

of United Way, one is a board As an organization, our Navajo member of the Phoenix Urban League, Generating Station provided litter bags one is vice president of Kiwanis, one is in northern Arizona to the surrounding president of a community drug abuse Lake Powell community to encourage organization, and another is on the a trash. free environment.

board of directors for the Scottsdale And in another people area Boys Club and the Arizona Center for labor we signed a new two.year the Blind. Our president serves as a contract in December with our member of the Salvation Army's electrical workers'nion. The contract Advisory Board. provided a 10.0 percent wage increase As an organization, SRP loaned four for hourly employees in 1981 and an executives to help administer the 8.3 percent increase in 1982.

community United Way program in We opened the doors to the past four Valley cities for four weeks. We with the dedication of the Silva House, also loaned executives to the Girl a restored turn. of the. century Phoenix Scouts and Gompers Rehabilitation residence which now serves as a Institute. historical museum. The house and Employees gave their blood. several others were restored as part of Throughout the state they contributed a City of Phoenix renovation park more than 700 pints to Arizona Blood project Silva House features SRP Services. memorabilia and historical displays We supported career counseling. and is open free to the public.

Representatives attended the Native Our 19.member citizens task force American College of Engineering that we established in 1979 as part of Program sponsored by the Navajo the Public Utilities Regulatory Policies Nation at Northern Arizona University Act (PURPA) met 29 times during the and the University of New Mexico. In year. They will continue to meet in 198142, evaluating such issues as time~f4ay rates, load management techniques and lifeline rates. The group will make recommendations to our board of directors by October 1981.

15 Financial commentary The financial statements in this during the fiscal year. In October Rates increase report couer the fiscal year of May 1, $ 100.0 million were sold at an effective 1980 through April 30, 1981. interest rate of 9.35 percent and $75.0 Water rates increased an average of million were sold in March at an 12.5 percent in December, while Innovative financing effective interest rate of 10.59 percent. electric rates rose an average of 12.8 percent in April. Both increases were helps offset inflation We also sold 42.2 million in $500 denomination "mini bonds," to local less than the 13.5 percent rise in the We attacked inflation in several investors. The "minis" carry maturities Consumer Price Index for all urban ways during 198081. The most from 1985 to 1989, and bear interest consumers reported in early 1981.

unusual way was our entrance into the rates ranging from 6 1/4 percent to 7 taxwxempt commercial paper market. 1/4 percent. This marked the second Operating revenues In August of 1980, our Board of year such bonds were offered; the climb 20 percent Directors approved the issuance of up previous year, we sold 41.1 million to ~225 million in commercial paper. worth. Operating revenues totaled $ 539.7 Enthusiastic investor interest rapidly Net financing costs, less allowances million, an increase of $ 90.1 million, or built up the size of the program, and for funds used during construction, 20.0 percent, from 1979.80's amount since January, 1981, the average were $47.5 million in 1980.81, of $449.6 million.

amount of paper outstanding has compared to $31.0 million in 1979.80. Electric operating revenues exceeded $215 million. The average increased by 20.1 percent, or $ 89.5 Funds available for debt service interest rate on all paper issued amounted to $263.7 million, up from million, from 4444.9 million to $ 534.4 through April 30, 1981, was 5.75 $ 223.3 million the previous year. million. The increase was due largely percent. Proceeds were used to to higher electric rates that took effect provide fossil fuels and interim Sales help reduce in April, 1980, and also to increased customers and sales.

construction financing. This short. term financing method provides a lower requirements for Energy sales rose by 11.5 percent, interest rate than long term bonds and long-term financing to 12 billion kilowatt hours. Although a greater flexibilitythan other financing statewide copper strike which lasted methods because it enables us to take The peak demand for power has five months caused a decline in increased only 2-to-3 percent a year industrial energy sales, most of the advantage of the great demand for money market investments. during the late 1970s and early 1980s energy the striking mines did not use instead of the 7.to-8 percent a year was sold to other utilities. Sales for Debt service coverage which was predicted prior to the Arab oil embargo. As a result, we found resale proved to be a significant source of revenues, totaling $ 112.6 improves; bonds sold ourselves with too much generating million, an increase of 44.9 percent.

Our debt service coverage ratio at capacity. In response we decided to Residential sales revenue increased the end of the fiscal year was 1.74, sell 25.0 percent of our ownership in by 13.9 percent, from $ 186.6 million compared to 1.70 at the end of the the Palo Verde Nuclear Generating in the previous 12 months to $212.5 previous fiscal year. Bond ratings Station under construction west of million. Combined revenues from remained at "Aa" from Moody's Phoenix However, we will continue to commercial and industrial sales grew Investor Service, Inc., and "A+" from own 670,000 kw of the station when it by 14.4 percent to $ 1 82.6 million, Standard and Poor's Corp. begins operating and we retain faith in from $ 159.6 million.

We sold three issues of tax exempt nuclear energy as a safe and efficient Revenues from the remaining revenue bonds totaling $ 177.2 million power source. The pending sale to the customer classes-street and highway Southern California Public Power lighting, agricultural pumping and Authority, with the Los Angeles public authorities-increased by 31.1 De partment of Water and Power as percent, or S5.5 million, from $ 17.7 agent, will reduce our capital million in 1979.80, to $23.2 million.

requirements by $423.7 million Water revenues rose by 12.8 between now and 1988. percent, from S4.7 million to S5.3 We also completed agreements for million. The increase was due to the sale to Tucson Electric Power Co. higher water charges.

of half our interest in the railroad spur continued to the Coronado Generating Station.

Tucson Electric will use the spur for delivering coal to its plant being built near Springerville. Proceeds to SRP will total more than $22.0 million.

Financial commentary Hew borrowing caused net Operating expenses financing costs to total $ 112.4 million, increase too 21.4 percent more than last year' Operating expenses increased by amount of $ 92.6 million. However, an 23.4 percent, or $ 75.8 million, from increase of ~4.2 million in interest on

~324.5 million to $400.3 million. Fuel temporary investments offset and purchased power together totaled somewhat the increase in financing

$ 160.0 million, an increase of 17.4 costs. Net financing costs less percent or $23.7 million. Most of the allowance for funds used for increase was the result of additional construction charged to current fuel needed to produce more operations amounted to $47.5 million, electricity; demand increased due to an increase of $ 16.5 million-53 customer growth coupled with an percent-over last year. The large abnormally hot summer. increase was due to new borrowing at The average cost per kilowatt.hour high interest rates.

for residential customers rose from Net revenues totaled ~93.5 million, 5.28 cents to 5.78 cents. compared to $ 93.6 million last fiscal Other operation expenses increased year. More than $ 30 million of those

$ 15.1 million, from $ 60.1 million to revenues resulted from excess energy

$ 75.2 million, or 25.1 percent. Higher sales. Net revenues are not considered prices for labor, materials and services as profit. Rather, they are reinvested in contributed to the expense increase. our plant and used for repayment of Maintenance costs increased S6.7 principal and long term debt.

million, or 15.2 percent, from ~44.2 million to $ 50.9 million. 'The increase was due mainly to new facilities at Coronado Generating Station.

Depreciation charges rose by $ 17.3 million, from $38.8 million, while taxes and tax equivalents increased $ 12.9 million, from 445.2 million to $ 58.1 million. Increases in these latter two categories reflect the increasing investment in plant and equipment, as the second units of the Craig and Coronado generating stations began commercial operations.

Combined statements of net revenues Salt River Project Agricultural Improvement and Power District 17 and its agent, Salt River Valley Water Gsers'ssociation (Oooo) 12 Months Ended April 30 OPERATING REVENGES: 1981 1980 Electric . ~534,357 , ~444,887 Water and irrigation. 5312 ',696 Total operating revenues 4539.669 4449.583 OPERATING EXPENSES:

Power purchased S 20,852 ~ 27,598 Fuel used in electric generation 139,112 108,657 Other operation expenses . 75,175 60,106 Maintenance 50,927 44,160 Depreciation and amortization (Note I). 56,123 38,787 Taxes and tax equivalents 58 134 45 199 Total operating expenses. 4400 323 >324 507 NET OPERATING REVENGES 4139 346 4125 076 FINANCING COSTS:

Interest on bonds at coupon rates >130,364 ~111,268 Amortization of bond discount and issue expense 1,686 1,421 Amortization of loss on defeased debt 976 976 Interest on other obligations . 13,478 8,887 Interest earned on investments and deposits ~34.080 ~29,923)

Net financing costs ~112,424 ~ 92,629 Less ~

Allowance for funds used during construction (iYote 1). ~(64.964 (61,633)

Financing costs less allowance for funds used during construction........ 4 47460 > 30996 OTHER INCOME (DEDUCTIONS), NET 1 644 493 NET REVENUES FOR THE YEAR > 93.530 ~ 93,587 7he accompanliing notes are an integral part of these combined statement.

Combined Balance Sheets Salt River Project Agricultural Improvement and Power District and its agent, Salt River Valley Water Users'ssociation 18 Assets (oooo) 12 Months Ended April 30 1981 1980 UTILlTYPLANT, at original cost (/Yotes /, 2, 3 and 4)t Plant in service Electric . 41,822,013 S1,482,102 Irrigation . 70,756 68,315 General . 63 705 52,346 Total plant in service $ 1,956,474 ~1,602,763 Less - Accumulated depreciation on plant in service 356,384 302,721

~1,600,090 $ 1,300,042 Construction work in progress 886,773 890.738 42 486 863 ~2.190,780 SEGREGATED FUNDS, consisting of cash and G.S.

Government obligations set aside in accordance with resolutions of bond issues:

Debt service funds, excluding $45,891,000 in 1981 and

$ 42,989,000 in 1980 for payment of accrued interest

(/Yote 5) 146,920 135,443 Construction funds. 70 295 146,990 135,738 CGRRENT ASSETS:

Cash 873 180 Temporary investments, at cost, held primarily for construction. 109,129 116,621 Deposit in debt service fund for payment of accrued interest on bonds........ 45,891 42,989 Trade and other accounts receivable, less reserves of ~1,420,000 in 1981 and

$ 1.415.000 in 1980 for doubtful accounts . 45,532 41,657 Fuel stocks, at average cost 94,033 92,141 Materials and supplies, at average cost. 28,106 24,080 Prepayments, interest receivable and other 10,930 10,355 4 334494 4 328023 DEFERRED CHARGES AND OTHER ASSETS (/Yote /) .. 58 392 60438

~3,026,739 $ 2,714,979 7he accompanying notes are an integral part of these combined balance sheets.

19 Combined Balance Sheets Capitalization and Liabilities ~4000) 12 Months Ended April 30 1981 1980 LONG-TERM DEBT (/Yote 5):

Electric system. revenue bonds. $ 1,940,e44 $ 1,777,220 General obligation bonds and other 268 432 ~24 778

$ 2,209,276 $ 2,019,998 ACCGMGLATED NET REVENGES, invested principally in utility plant:

Balance beginning of year . 4 377,908 284,321 Net revenues for the year 93,530 93,587 Balance end of year 471 438 4 377908 Total capitalization <2 680 714 42 397,906 CGRRENT LIABILITIES,excluding $ 22,105,000 in 1981 and

$ 21,381,000 in 1980, representing current portion of long term debt which is to be paid from segregated funds:

Short. term promissory notes (IYote 7) 174,090 Notes payable to banks (Yote 7) 120,000 Accounts payable 66,826 84,212 Accrued taxes and tax equivalents. 35,490 29,855 Accrued interest 46,382 45,593 Customers'eposits. 7,713 6,592 Other current and accrued liabilities . 9 542 22,001 340,043 308,253 DEFERRED CREDITS AND RESERVES 5 982 8 820 COMMITMENTS AND CONTINGENCIES (JYotes 3 and 6)

~3,026,739 $ 2,714,979

Combined statements of sources of funds for additions to utility plant Salt River Project Agricultural Improvement and Power District and its agent, Salt River Valley Water Users'ssociation 20 (F00) 12 Months Ended April 30 1981 1980 GROSS ADDITIONS TO UTILITYPLANT, excluding allowance for funds used

$ 302 702 $ 412 51 0 during construction.

FUNDS GENERATED FROM OPERATIONS:

Net revenues for the year . ~ 93,530 ~ 93,587 Add Depreciation (including charges to clearing accounts) and

~

other charges not requiring current funds 62,883 43,881 Deduct - Allowance for funds used during construction not providing current funds . 61,633 Total funds generated from operations before retirement of debt 4 91,449 ~ 75,835 Less - Repayment of long term debt from segregated funds (21,785) (19,173)

Net funds generated from operations. S 69664 S 56662 FUNDS OBTAINED FROM FINANCING:

Proceeds of bond issues . $ 168,843 $ 287,521 Advances from U.S. Government for rehabilitation of irrigation plant . 388 1,301 Contributions in aid of construction . 11,406 6,680 Other long-term borrowings, net of repayments . 40,421 (776)

Short. term borrowings, net of repayments 54,090 20,000 Total funds obtained from financing. 4275,148 $314,726 Other ~

Increase in segregated funds set aside for debt service (11,477) (21,496)

Decrease (increase) in segregated funds set aside for construction... 225 (94)

Decrease in temporary investments held primarily for construction... 7 492 84 412 Net funds obtained from financing . $ 271,388 $377,548 CHANGES IN OTHER ITEMS AFFECTING FUNDS:

increase (decrease) in accounts payable . 4 (17,386) S'9,891 Increase in accounts receivable . (3,875) (6,044)

Increase in fuel stocks and materials and supplies (5,918) (64,456)

Increase in deposits for payment of accrued interest on bonds . (2,902) (8,158) increase in accrued interest . 789 10,357 Change in other assets and liabilities, net. ~9058 6,710 Net change in other items . ~<38 350 ~

~$ 21.700 FUNDS USED FOR A'DDITIONS TO UTILITYPLANT $ 302 702 $ 412 510 The accompanytng notes are an integral part of these combined statements.

Notes to combined financial statements 21 For years ended April 30, 1981 and 1980 (1) Summary of significant accounting employees. The phn is funded entirely from and the earnings of the invested assets. The employers'ontributions policies: estimated unfunded past service liability, as determined by the plan's actuary using the "entry age normal cost" valuation method, (a) Principles of Combination with frozen initial liability, was $ 10/63,698 as of January 1, 1981.

The combined financial statements include the accounts of the This amount is being funded and amortized over a period ending in Salt River Project Agricultural Improvement and Power District ("the 2011. The employers'ontributions to this plan totaled $8,444/21 District") and the accounts of its agent, the Salt River Valley Water for 1981 and $ 7,800,891 for 19SO.

Gsers'ssociation, together referred to as the Salt River Project At January 1, 19S1, the Plan's assets exceeded the actuarially

("the Project" ), and a whollyawned subsidiary, Salt River Generating computed value of the vested benefits at the same date. The Company. All significant intercompany transactions have been actuarially computed present value of the vested and nonvested eliminated. benefits was $49,552/01 and $8,674,720, respectively. The market (b) Change in Accounting and Reporting Period value of the Plan's net assets was ~72,649,465 at January 1, 1981.

On October 19, 1979, the Board of Directors approved a change The assumed rate of return in determining the actuarial present in the accounting and reporting year from a calendar year to a fiscal value of vested and nonvested plan benefits was 7-1/2X.

year, May 1 through April 30 basis.

This change was made to coincide more closely with the (h) Revenues Meters for residential, commercial and small industrial customers Project's natural business year and should improve the Project's are read cyclically and sales recorded only when billed. This system ability to more accurately project and budget for the following year. of billing results in earned but unbilled revenues which amounted (c) The Project's Board of Directors serves as its regulatory agent, to $ 11,816,648 at April 30, 1981 and 610,677,100 at April 30, 1980. For large industrial customers, meters are read near month.

(d) UtilityPlant, Depreciation and Maintenance end and billings recorded on the accrual basis. Electric revenue The accounting records of the Project are maintained billings are adjusted periodically for changes in costs of fuel and substantially in accordance with the Gniform System of Accounts purchased power. Revenues from water and irrigation operations prescribed for eiectric utilities by the Federal Energy Regulatory are recorded when earned.

Commission. Gtility phnt is stated at the historical cost of construction. Construction costs include labor, materials, services (l) Electric Rates purchased under contract, and allocations of indirect charges for Gnder Arizona law, the District Board of Directors has the exclusive engineering, supervision, transportation, and administrative authority to establish electric rates. The District is required to follow expenses. certain procedures, including certain public notice requirements An allowance for funds used to finance construction work in and holding a special Board meeting, before implementing any progress is capitalized as a part of the electric and general plant. changes in the standard electric rate schedules. A general rate This allowance is deducted from net financing costs in the increase of 12.8X approved by the District's Board on February 12, combined statements of net revenues and added to utility plant. 1981 became effective April 1, 1981.

Capitalization rates of SA8X, 8.2X and 72X were used for the year ended April 30, 1981, and the period of January 1, 1980 through (2) Possession and use of utility plant:

April 30, 1980 and the period of May 1, 1979 through December The Gnited States of America retains a paramount right or claim 31, 1979, respectively. in the Project which arises from the original construction and Depreciation expense is computed on the straight line basis over operation of the Project's facilities as a Federal Reclamation Project.

estimated useful lives of the various classes of plant. Rates in effect The Project's right to the possession and use of, and to all revenues resulted in provisions approximating 3.42X for 1981 and 3.46X for produced by, these facilities is evidenced by contractual 1980 on the average cost of depreciable electric plant; and 1.99X arrangements with the Gnited States.

for 1981 and 1.94X for 1980 for depreciable irrigation plant. When property representing a retirement unit is replaced, removed, or abandoned, the cost of such property is credited to the appropriate (3) Construction program:

utility plant account, and such cost together with removal costs less Balances shown for construction work in progress represent salvage is charged to accumulated depreciation. expenditures for new facilities required to service anticipated customer The Project charges to maintenance expense the cost of labor, needs, and consist of:

materials, and other expenses incurred in the repair, restoration of ~ICOD) condition and replacement of minor items of property. April 30 1981 1980 (e) Bond Expense Electric generating facilities..................... S836NS S852576 Bond discount, premium and bond issue expense are being Transmission and distribution................... 34,081 20,771 amortized over the terms of the rehted bond issues. Irrigation plant . 4577 5.983 Other construction 11206 11A08 (f) Unamortized Loss on Defeased Debt In April 1978 and August 1977, electric system revenue bonds Total .. S886.773 S 890.738 were sold. Portions of the proceeds of these bonds were used to Construction expenditures (net of estimated proceeds from Pab defease ~210,000,000 of the outstanding electric system revenue Verde sale in 1982 of $2129 million) phnned for 1982 through bonds. These defeasances resulted in gross savings in debt service 886 approximate $ 129,925,000; $300,340,000; $213,102,000; over the lives of the new issues of $32@00,000. The combined $ 217/05,000 and $ 21 7,937,000, respectively.

. financing costs of the defeasances were $26,055,000. The District At April 30, 1981, necessary commitments had been entered Board of Directors approved deferral of the financing costs and into for delivery of materials and services on construction projects.

their amortization over the lives of the April 1978 and August 1977 In addition, various firm commitments exist under coal and fuel oil issues. supply contracts.

(g) Employees'etirement Plan Palo Verde iYuclear Generating Station (PVIYGS):

The Project has a retirement plan covering substantially all The Project has a 29.1X interest in the PIGS. However, the

Notes to combined financial statements 22 District has entered into an arrangement with the Department of (a) Electric system revenue bonds are secured by a pledge of, Water and Power of the City of Los Angeles which provides for the and a lien on, the revenues of the ekctric system after deducting transfer of a 5.7X interest in PVNGS when Gnit 1 goes into "operating expenses," as defined in the bond resolutions, subject to commercial operation. From information now available, the Project prior liens of general obligation bonds of ~213,887,772 and cannot assess whether the construction schedule used for Gnits 1, amounts due the Gnited States of 612,691388. In all years to date 2 and 3 will be affected by delays in the issuance of licenses as a electric revenues, after deducting "operating expenses" as defined result of the Three Mile Ishnd incident. in the bond resolutions, have been more than sufficient to meet all Projected construction expenditures include a contingency debt service requirements.

allowance to reflect the possibility of one-year delays in the (b) General obligation bonds are a lien upon the real property completion of Gnits 2 and 3, and the possibility of more stringent included in the District and are additionally secured by a pledge of regulatory requirements related to nuclear facilities. There can be revenues from the operation of the electric system. If the net no assurance that this provision will be adequate to cover possible electric revenues, as defined in the bond resolutions, are not increased costs associated with any major changes mandated by suHicient to meet the principal and interest payments, the bonds regulatory agencies as a result of the Three Mile Island incident. and interest are payable from a levy of taxes on the real property.

The annual maturities of bonds and other long term debt (4) Interests in jointly owned electric outstanding as of April 30, 1981 due in each of the fiscal years utility plants: ending April 30, 1982 through 1986 are ~23,219,000; 665,150,000; 625,312,000; 627/01,000 and 628,490,000, respectively.

The Project has entered into various agreements with other Interest and amortization of discount on the various issues electric utilities for the joint ownership of electric generating and outstanding during the year resulted in an effective rate of 6.43X for transmission facilities. Each participating owner in these facilities 1981 and 6.11% for 1980. This rate approximates 6.94% over the must provide for and furnish the financing for its ownership share. remaining terms of the bonds.

The following schedule reAects the Project's ownership interest (at The debt service portion of segregated funds includes cost) in jointly owned electric utility plant at April 30, 1981. 633,504,000 at April 30, 1981 and 629309,000 at April 30, 1980, In Millions restricted for operating reserve requirements under bond Construction resolutions.

Ownership Plant Shore In Accumulated Work In Electric system revenue bonds totaling 6103,643,000 principal Plant rfnme Sentce Deprechtion Progress amount are authorized, but unissued. Electric system refunding

$ 2].6 $ 7.6 $93 revenue bonds not to exceed 6115,000,000 principal were also 325 93 2.7 authorized, but unissued.

205.1 36.0 2.1 101.6 6493 15.9 228 1.1 63 (6) Litigation:

S1 2202 3.6,1 233.9 6.6

$ 983

(.5) 762$

$ 787$

Enuironmenfalr Various pending litigation or administrative proceedings involving environmental matters could affect interests owned by the Project in On April 14, 1981, the Salt River Project Board of Directors present and proposed generating facilities. In general, these hwsuits approved a sale to the Southern California Public Power Authority seek to impose higher air quality standards for generating plants. If of approximately 225 megawatts of the Project's interest in the Palo ultimately decided adversely to the interest of the Project, the Verde Nuclear Generation Station. Although contracts have not outcome of the lawsuits could result in increased construction been completed, it is anticipated that the transaction will be costs, increased future operating costs, and a possible loss in the finalized by February 1, 1982. The sale price is estimated at 62129 operational reliability of certain generating phnts. All of these million. effects would increase the costs to be passed on to customers The Project's share of direct expenses of the jointly owned plants through increased electric rates.

is included in the corresponding operating expenses in the attached combined statements of net revenues. IYauajo Tax:

The Navajo Tribe has created a Tax Commission which claims authority to tax facilities on the Navajo Indian Reservation. The (5) Long-term debt: Tribe has adopted a possessory interest tax and a business activity

($ 000) tax on certain facilities and operations on the Reservation, and the Sedes Interest Rate Future District is informed that such taxes are intended to apply to the Siectrlc System Revenue Bonds (n): 1981 1980 Maturltles Navajo and Four Comers Projects. The District is unable to 1973 A 6 B.......... 5 to 6 I/2 140.220 $ 142205 1982 2011 estimate the magnitude of the possessory interest tax because of its 1974 A 6 B..........5.7 to 7.6 140,000 140,000 1983 2012 inability to interpret the way the tax is to be calculated. The District 1976 A.B,C, 6 D......4 I/2 to 72 403,200 404,150 1982.2016 1977 A, B Refund.

estimates that the business activity tax, if upheld by the courts, ing 6 C ...........4.1 to 6 I/8 392.3% 394215 1982.2017 could expose it to claims approximating 64.6 million per year. The 1978 A,B 6 C........4.1/2 to 7 316,435 317,900 1982.2018 District and other Navajo and Four Comers Project co owners have 1979 AB 6 C ........4.3/4 to 7 I/4 280,967 281.077 1983 2019 liled actions in the Federal District Court for Arizona and New 1980 A,B 6 C........ &I/4 to 9 I/4 227,245 125,000 1985 2020 Mexico contesUng the validity and imposition of the taxes. The 1981 A..............9 to 14 75.000 1987 2021 District has appealed a decision from Federal District Court for SI,975/32 $ 1/$ 4547 Arizona upholding the right of the Tribe to impose the possessory Unamortized bond discount ..... (34,588) (27327) interest tax to the Ninth Circuit Court of Appeals.

Totnl eiectdc system revenue The Navajo Tribal Council has adopted resolutions which, if bonds outstanding ........... SI ~,844 $ 1,777220 valid, require permits and the quarterly payment of taxes for General Oblgation Bonds and emission of sulphur at rates which commence at 6.15 per lb. the Other, 1$ $ to 10.8% (b): ..... 268,432 242.778 1981.2005 first year and increase annually to 6.75 per lb. in the fifth year. The Total long. term debt............ <2209,276 >2,019,998 District and other Navajo and Four Comers Project co owners filed actions in Federal District Court for Arizona and New Mexico

23 Notes to combined financial statements protesting the resolutions. Ihe tax will become effective subsequent The District's Board has authorized the issuance of up to to either approval of the Secretary of the Interior or a finding by ~225,000,000 in short term promissory notes (the "Notes" ). The him that such approval is not required. If such tax is upheld by the Notes are being sold in the tax exempt commercial paper market.

courts, the District could be exposed to claims approximating $3 The Notes will mature in no more than 270 days from the date of million in the first year and increasing to ~15 million in the fifth year issuance and in no event after August 1, 1983. Ihe Notes are and each year thereafter. issued in minimum denominations of 450,000 in bearer or The assertion by the Tribal Council of taxing and regulatory registered form without coupons, and bear interest from their date authority on the Navajo Indian Reservation has caused the Board of at an annual interest rate not to be in excess of 12X.

Directors of the District to adopt a resolution allowing it to recover The indebtedness of the District evidenced either by the Notes or from its customers the amounts of such taxes if the payment boirowings under the Agreement is an unsecured obligation of the thereof is ultimately required. District payable from the general funds of the District lawfully Other. available therefor, subject in all respects to the prior lien of Prior Principally as a result of certain water flooding in March and Lien Bonds, Revenue Bonds and other indebtedness of the District December 1978, and February 1980, various lawsuits have been secured by revenues or assets of the District. No specific revenues filed against the Project alleging that the Project has a responsibility or assets of the District are pledged to the payment of the Notes or in regard to flood control and a liability in regard to flood damage. borrowings under the Agreement and the Notes and such The ultimate liability, if any, is not determinable, but boirowings are not payable from taxes.

management expects that a significant portion of any liabilities Borrowings under the Agreement and through the issuance of which might result from flood damage claims will be covered by the Notes have been used to refinance the District's former line of insurance. credit borrowings. As of April 30, 1981, the District had

$ 40,000,000 in borrowings outstanding under the Agreement at an (7) Revolving credit agreement/ interest rate of 10.80X. As of April 30, 1981, the District had S174,089,601 of the Notes outstanding at an average interest rate commercial paper program: of 5.50X. Borrowings under the Agreement are being accounted for by the District as long term debt. Proceeds from the sale of the On August 4, 1980, the District entered into a revolving credit Notes are intended to be used for construction expenditures and to agreement (the "Agreement" ) with a group of eighteen banks led Iinance the District's fuel inventories.

by First Interstate Bank of Arizona, NA. Under the terms of the The District's Board has limited the total amount of promissory Agreement, the District may borrow up to ~225,000,000, until notes which may be outstanding at any one time under the August 1, 1982. If the Agreement is not renewed prior to August 1, Agreement and in the tax~empt commercial paper market to an 1981, the District may continue to borrow but must reduce its aggregate of $225,000,000.

outstanding borrowings to not more than ~112~,000 by August 1, 1982. Following August 1, 1982, the District may not make additional borrowings and must repay all outstanding borrowings by (8) Irrigation and water operations:

August 1, 1983. Borrowings under the Agreement initially bear Imgation and water operations expenses, including depreciation, interest at a rate equal to 60X of the lead bank's prime rate as exceeded the assessments, delivery fees and other revenues established and announced from time to time. No compensating therefrom by approximately $4,870,000 for 1981 and $ 10,779,000 balances are required under the Agreement. A commitment fee of for 1980. These amounts do not include expenditures for additions I/2 of 1X per annum is payable on any unused portion of the and improvements to irrigation phnt and for repayment of long.

$ 225,000,000 commitment to lend. term debt.

Auditors'eport We have examined the combined balance sheets of SALT RIVER PROJECT AGRICULTURALIMPROVEMENT AND POWER DISTRICT (a political subdivision of the State of Arizona) and its To the Board of Directors, agent, SALT RIVER VALLEYWATER USERS'SSOCIATION, Salt River Project Agricultural Improvement and Power District, and together referred to as the SALT RIVER PROJECT, as of April 30, Board of Governors, 1981 and 1980, and the related combined statements of net Salt River Valley Water Users'ssociation: revenues and sources of funds for additions to utility plant for the years then ended. Our examinations were made in accordance with generally accepted auditing standards and, accordingly, included such tests of the accounting records and such other auditing procedures as we considered necessary in the circumstances.

In our opinion, the financial statements referred to above present fairly the financial position of the Salt River Project as of April 30, 1981 and 1980, and the results of its operations and sources of funds for additions to utility plant for the years then ended, in conformity with generally accepted accounting principles applied on a consistent basis.

Phoenix, Arizona, ARTHUR ANDERSEN 6 CO.

June 12, 1981.

Statistical review 24 (F00) 12 Months 12 Months Ended April 30 Ended December 31 PROJECT GENERAL 1981 1980 1975 1970 Operating revenues ~539,669 ~449,583 $ 213,838 ~74,537 Electric 534,357 444,887 211,016 72,600 Water and irrigation. 5,312 4,696 2,822 1,937 Operating expenses 400,323 324,507 180,048 62,521 Net financing costs less capitalized interest 47,460 30,996 23,821 2,862 Other deductions (revenues), net. (1,644) 493 (445) 516 Net revenues. 93,530 93,587 10,414 8,638 Construction expenditures. 302,702 412,510 166,328 49,993 Electric and irrigation plant, gross. 2,843,247 2,493,501 984,756 363,294 Contributions of power revenues to support water operations 4,870 10,779 7,248 9,200 Taxes and tax equivalents ~ 58,134 45,199 26,278 7,746 Employees at year.end. 4,580 4990 3205 2439 WATER* 1980 1979 1975 1970 Total storage and pumping capacity (acres'eet) .. 2,891,711 2,858,261 2,869,649 2,911,597 Storage capacity (six reservoirs) 2,063,948 2,063,948 2,072,050 2,072,050 Installed pumping capacity 827,763 794,313 797,599 839,547 Water in storage January 1 (acre. feet) 1,563,309 1,839,399 1,056,410 1,365,502 Project storage only 1,290,971 1,548,742 798,815 1,046,630 Runoff (acre. feet) 2,879,637" 2,421,056 870,511 644,527 Water in storage December 31 (acre feet) 1,480,332 1,563,309 1,040,000 1,090,552 Project storage only 1,227,055 1,290,971 771,440 784,312 Total water deliveries (acre feet) . 1,446,277 1,338,008 1,194,21 2 1,257,918 Gravity supply 1370,310" 1,264,344 849,875 847,980 Groundwater supply (pumping by SRP) 65,648 65,596 337,51 6 400,430 Groundwater supply (pumping by others) 10,319 8,068 6,821 9,508 Use of water (acre feet) . 1,446,277 1,338,008 1,194,212 1,257,918 Agricultural. 579,650 535,046 447,042 521,034 Urban 362,758 334,309 265,591 209,020 City domestic . 247,190 222,098 160,998 122,077 Subdivision irrigation 57,831 55,063 54,252 48,874 Other nonagricultural irrigation (schools, parks, churches, etc.) 57,736 57,148 50,340 38,070 Decreed deliveries. 67,762 64,505 55,236 54,546 Contract deliveries 192,909 166,606 59,255 56,618 Seepage and evapotranspiration. 243,197 237,541 367,089 381,321 Canals, total (miles) . 131 131 131 131 Uned . 64 64 57 48 Laterals, total (miles) . 880 880 876 881 Lined or piped 749 740 702 573 Drainage and waste ditches (miles) . 247 247 254 277 Lined or piped 60 58 53 46 Assessed area (acres),. 238,221 238,221 238,264 238,264 Number of assessed accounts. 177,171 174,603 161,869 142,588 Number of times water delivered to water users .. 480,306 444,157 469,071 478,228

'Statistics on water are computed on a caiendar year basis "Based on tj.S.GS. provisional records and subject to adjustment

25 Statistical review POWER 12 Months Ended April 30 12 Months Ended December 31 1981 1980 1975 1970 Energy sources (kwh)

Net steam generation'et 10,385,225,000 8,847,016,000 4,050,267,000 2,752,126,320 combustion turbine generation . 62,336,000 43,497,000 144,899,000 Net combined cycle generation .... 4,110,000 87,953,000 706,469,000 Net run of river generation ........ 468,174,000 511,526,000 297,858,000 276,396,000 Pumped storage generation ....... 118,324,000 100,455,000 81,916,000 Total net generation* 11,038,169,000 9,590,447,000 5;281,409,000 3,028,522,320 Purchased 2,098,800,686 2,1'1 0,570,024 3,51 5,476,241 1,747,477,914 Interchange received . 145,837,000 345,460,000 211,365,000 444,453,833 Wheeling received. 9,793,314 7,772,976 38,378,759 35,174,938 Total energy sources'......... 13,292,600,000 12,054,250,000 9,046,629,000 5,255,629,005 Energy disposition (kwh)

Residential . 3,674,758,035 3,533,960,873 2,878,957,582 1,655,829,183 Commercial 6 industrial .......... 4,430,656,608 4,413,323,586 3,387,045,196 2,204,565,724 Irrigation pumping .. 243,257,760 204,961,011 310,750,959 242,855,454 Street 6 highway lighting.......... 43,203,039 42,781,200 39,259,768 29,418,164 Public authorities. 351,055,276 297,550,699 260,297,826 195,562,777 Interdepartmental . 80,008,412 63,612,338 176,855,758 201,359,366 Sales for resale . 3,205,534,954 2,232,292,703 988,241,889 212,682,954 Total sales . 12,028,474,084 10,788,482,410 8,041,408,978 4,742,273,622 interchange delivered . 245,224,000 330,956,000 279,381,000 ] 1],467,788 Wheeling delivered 9,024,579 7,110,294 34,847,914 32,958,919 Energy losses . 840,845,337 784,193,296 574,735,108 368,928,676 Energy for pumped storage operation .. 169,032,000 143,508,000 116,256,000 Total disposition of energy......... 13,292,600,000 12,054,250,000 9,046,629,000 5,255,629,005 Peak overall power system (kw).......... 2,386,000 2,337,000 1,939,000 1,172,000 Date and time (MST) August 11, 6 p.m. Sept. 5, 6 p.m. Aug. 6, 3 p.m. July 15, 6 p.m.

Peak Project customers (kw) .. 2,057,000 1,911,000 1,634,000 1,055,000 Date and time (MST) July 28, 5 p.m. June 27, 5 p.m. Aug. 6, 3 p.m. July 15, 6 p.m.

Generating capability (kw)"

Steam' 1,919,250 1,553,250 1,181,900 697,400 Combustion turbines 393,000 393,000 424,800 Combined cycle ....... 288,000 288,000 292,000 Hydroelectric conventional.............. 95,000 95,000 94,300 72,600 Hydroelectric pumped storage .......... 137,000 137,000 147,200 Total operating capability'.......... 2,832,000 2,466,250 2,140,200 770,000 Contract purchase at time of peak....... 329,547 328,661 450,500 611,912 Total resources' 3,161,797 2,794,911 2,590,700 1,381,912 Electric customers ~

year end Residential . 305,870 290,161 230,712 156,401 Commercial 6 industrial ... 22,771 21 40] 16,918 12,428 Other 1,610 1,573 ],296 944 Total. 330,251 313,135 248,926 .- ]69,773 Average annual kwh use-Residential . 12,014 12,557 12,843 10,913 Average annual kwh revenue-Residential (cents) . 5.78 5.28 3.29 2.00

'includes SRP participation in jointly owned projects.

"Unit capabilities during summer peak.

Board Members 26 The 10 members of the Board of Governors of the Salt River Valley Thomas P. Huriey Distnct 6

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Water Users'ssociation are elected every two years by the shareholders (property owners) of the Association.

The Board of Directors of the Salt River Project Agricultural Improvement and Power District consists of 14 members. One District Board member is elected from each of the 10 SRP geographical areas, and four members are elected at. large. Two of the four at.

large members were elected during 198081.

Thomas M. Omens, Jr.

District 8

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Board members establish the policies for the management and conduct of Salt River Project's business affairs.

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I XO John M. Williams, Jr. John L. Burton, Jr.

Dislrict 5 A At large Germain H. Ball District I Fred J. Ash At large M

27 Board members

~ William P. Sehrader District 7 Alex M. Conooalaff District 2

. Larkin Fitch Thomas J. Finley istrict 9 District l0 William W. Arnett At.large

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r. Stanford J. Hartman t.large Bruce B. Brooks A District 3 Gilbert R. Rogers District 4

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Council Members 28 Three council members are elected Salt River Project Agricultural for two year terms from among the shareholders in each of the 10 district Improvement and Power District. Half the District council seats come up for r Elvin E FIeming (left) and Brooks Jr., District 3.

areas of the Salt River Valley Water election every two years.

users'ssociation. Three council The councils enact and amend members are elected for four-year bylaws relating to the management terms from among shareholders in and conduct of SRP's business affairs.

each of the 10 division areas of the Officers Elected Officers Karl F. Abel John R. Lassen President Vice President Principal Officers and Other Executives Jack Pfister Leroy Michael, Jr.

General Manager Assistant General Manager, Robert F. Amos Planning 6 Resources Deputy General Manager William G. Beyer Paul G. Ahler Director, Project Planning Director, Human Resources Don Parlett John D. Jacobs Assistant General Manager, Director, Information Services Customer Services Roger B. Ludeman Carroll M. Perkins Roy W. Cheatham (left), Edmund iYauarr Director, Operations Services Assistant General Manager, A (center) and Cart E. Weiler, District 5.

Financial Services John R. McNamara Treasurer Associate General Manager, Power D. Michael Rappoport L Max Pace (left), Orlando R.

Trent O. Meacham Director, Government Affairs Hatch (center), and Otto B.

Assistant General Manager, lYeely, District. 10.

Power Construction 6 Maintenanc Richard H. Silverman Director, Law 6 Land John O. Rich Assistant General Manager, Paul D. Rice Power Operations Corporate Secretary Stephen M. Chalmers Consultants Director, Engineering Services Legal Advisers John M. Evans Jennings, Strouss 6 Salmon - -tl Manager, Electric System Auditors R. D. Johnson Arthur Andersen 6 Co.

Manager, Generation Consulting Engineers Reid W. Teeples Ford, Bacon 6 Davis, Incorporated Associate General Manager, Water Bond Counsel Don L. Weesner Mudge Rose Guthrie 6 Alexander Assistant General Manager, Water Financial Consultant R. W. Mason Smith Barney, Harris Upham 6 Co.,

Director, River Studies incorporated Stanley E. Hancock Assistant General Manager, Communications 6 Public Affairs

Council members

~ John E. Anderson, District 3 (left) and Dtoayne E Dobson, District 8.

W. CuItis Dana (left), Olen Sharp (center) and Robert W. Birchett, Joe Bob lYeely (left) and Martin Y District 9. Kempton, District 8

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George B. Willmoth (left) and Wayne A. Marietta, District 7.

Dean W. Letois (left), James L Diller (center) and James R. Marshall, District 6.

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'p fj- q II i Q', r vy Wilson Jr. (l<<ft) and Leoi H. Reed, C istrict 4.

, lj ot shotont C.C. Pendergast Jr. (left) and Council Chairman Marcel J. Boulais, District 2.

onrad Gingg, District 2 Yiley R. Baker, Distnct 4

. Warren Austin, District 7 Emil Rooey (left), Hotoard W. Lydic (center) and Rudolph Johnson, Distnct I.

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Salt River Project BULK RATE U.S. POSTAGE P.O. Box 1980 ~ Phoenix, AZ 85001 PAID PHOENIX, ARIZONA Return requested Permit No. 395 If you wish to receive a copy of next year's SRP Annual Report and you are not already on our mailing list, or if there is an error on our current mailing label, please write to:

Annual Report c/o Salt River Project Communications 6 Public Affairs P.O. Box 1980 Phoenix, AZ 85001 wC 84.90 I 0/741/7

FINANCIAL ANALYSIS AND RATE SCHEDULES FOR PROPOSED ADJUSTMENTS IN STANDARD ELECTRIC RATE SCHEDULES EFFECTIVE MARCH 1, 1981 SALT RIVER PROJECT AGRICULTURAL IMPROVEMENT AND POWER DISTRICT December 26, 1980

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TABLE OF CONTENTS 0

SUMMARY

OF RECOMMENDATIONS...,.......,........................................

SECTION A FINANCIAL STATEMENT REGARDING PROPOSED RATE INCREASE FOR 1989 INTRODUCTION.

OPERATING AND MAINTENANCE EXPENSES..

TAXES AND TAX EQUIVALENTS PRINCIPAL AND INTEREST ON BONDS OUTSTANDING 10 PROSPECTIVE PERFORMANCE FOR FISCAL YEAR 1980"1981 AND FISCAL YEAR 1981-1982 WITHOUT RATE ADJUSTMENT FINANCIAL CRITERIA. 15 PROSPECTIVE PERFORMANCE FOR FISCAL YEAR 1980"1981 29 AND FISCAL YEAR 1981-1982 WITH RATE ADJUSTMENT SECTION B MANAGEMENT'S RECOMMENDATION FOR REVISING STANDARD ELECTRIC RATE SCHEDULES INTRODUCTION.

35 RESULTS OF COST STUDIES AND PROPOSED INCREASES BY CUSTOMER CLASS . 37 RATE DESIGN . 47

SUMMARY

OF PROPOSED RATE REVISIONS.......... .. ~

51 REBASING OF FUEL ADJUSTMENT 55 CHANGES IN STANDARD ELECTRIC RATE SCHEDULES . 57 E-23 RESIDENTIAL SERVICE ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~

59 E-80 OPTIONAL RESIDENTIAL RATE WITHOUT DEMAND CHARGE...,................ 71 E-81 OPTIONAL RESIDENTIAL RATE WITH DEMAND CHARGE 79 E-82 OPTIONAL RESIDENTIAL FLAT RATE 87 Page 1 of 2

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E"35 COMMERCIAL AND SMALL INDUSTRIAL SERVICE. 93 E-36 TOTAL ELECTRIC SCHOOL OR CHURCH SERVICE......... 105 E"32 EXPERIMENTAL COMMERCIAL TIME-OF-DAY SERVICE.

E-39 LARGE INDUSTRIAL CUSTOMERS WITH DEMANDS ABOVE 5000 KILOWATTS 119 E-44 WIND MACHINESo ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~

125 E-47 AGRICULTURAL PUMPING 129 E"50- STREET IIGHTING SERVICE.... ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~

135 E-55 C"60 CHILLED WATER......... ~ ... ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~

RIDERS TO RATE SCHEDULES.. . 147 APPENDIX A: NOTES TO FINANCIAL STATEMENT NOTE 1 FISCAL YEAR 1979"1980 THROUGH FISCAL YEAR 1981-1982 DEBT SERVICE COVERAGE RATIO, DEBT RATIO, AND AVERAGE ANNUAL INTEREST RATE .149 NOTE 2: FINANCIAL CRITERIA AND SCORECARD . 152 NOTE 3: ECONOMIC GROWTH AND FINANCING REQUIREMENTS . 156 NOTE 4: STATISTICS . 160 APPENDIX B: FORECASTING METHODOLOGY .163 APPENDIX C: PUBLIC UTILITY REGULATORY POLICIES ACT . 175 GLOSSARY .179 Page 2 of 2

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SUEiARY OF RECOt91ENDATIONS I

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Management has assessed the financial position of the Salt River Project Agricultural Improvement and Power District (the Salt River Project) through the fiscal year ending April 30, 1982. 1 Based upon this eva1uation, management recommends an adjustment in standard electric rate schedules to be effective March 1, 1981. This adjustment should produce $ 5,641,000 in additional revenues in fiscal year 1980-1981, and $ 57,179,000 in additional revenues in fiscal year 1981-1982, representing a 13.7 percent increase in revenues under standard electric rate schedules.

The recommended rate adjustment is based upon inflation-induced increases in operating and financing expenses and on the need to meet debt service requirements adequately. Operating expenses are expected to increase at a rate higher than revenues, resulting in a serious decline in the Salt River Project's financial position. Financing costs are also expected to increase. In combination, these factors will adversely affect the Salt River Project's credit worthiness. This, in turn, would 'result in even higher interest costs and the possible inability to borrow, which would be detrimental to both the current and future ratepayers of the Salt River

Project, The following discussion summarizes the economic and financial factors which underlie the recommended rate adjustment. These factors are analyzed more extensively in Section A, which is supplemented by detailed notes (Appendix A) on specific points discussed in the text. (A glossary of fi'nan-cial and rate making terminology can be found after the appendices.) Appendix B, 1

The Salt River Project changed its fiscal year from the calendar year to the twelve-month period from Hay 1 to April 30, effective on May l, 1980.

Forecasting Methodology, explains the approach which the Salt River Project L

uses to formulate predictions of customer growth. These projections then become the basis for forecasts of sales, peak system demand, and ultimately, construction requirements.

As documented in Note 3 to Section A, Arizona has exhibited phenomenal growth over the past decade.

population increased by 41 Between 1969 and 1979, percent, over four and a half Arizona's times the percentage

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change for the United States as a whole, almost three times the percentage change for California and almost twice the percentage change -for Texas. The Phoenix area, within which the Salt River Project operates, has also grown dramatically. A comparison of the Phoenix area with other large communities (Standard Metropolitan Statistical'Areas) in the nation shows its outstanding record in terms of increases in population, housing starts, employment, and income.

As the area has grown, so has the number of electric customers served by the Salt River Project--but at an even faster rate in most years.

Over the period from 1970 to 1979, the population of Maricopa County increased by 49.7 percent, while the number of Salt River Project electric customers 1 increased by 82.4 percent.

Accompanying this rapid increase in the customer total has been an increase in energy consumption. In order to meet the increasing demands placed upon the electrical system, the Salt River Project has undertaken a major expansion of its generating facilities and related physical plant. This capital construction entails enormous costs. In general, the magnitude of such costs has been further amplified in recent years by inflation. In fact, price increases have affected all areas of operations--production as well as 11

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construction. Increases in costs of materials, labor, and other operating factors have all seriously impinged upon net revenues.

Because of the enormous costs involved with major construction projects, it is not feasible to finance such construction out of current internally-generated revenues. Furthermore, external funding (obtaining funds from outside the Salt River Project) avoids placing the bulk of the financing burden on existing customers. Borrowing allows the burdens, as well as the benefits, to be apportioned to ratepayers over time; that is, future'ustomers will also bear costs of constructing facilities adequate to meet their needs.

The Salt River Project is a political subdivision of the state, not, a private corporation. Consequently, it cannot issue equity capital, such as common stock, and so must rely on debt financing (such as revenue bonds) when seeking external sources of funds.

The credit rating of a company is crucial to the volume and cost of funds that it is able to borrow from investors. Currently, the securities issued by the Salt River Project, revenue bonds, are rated as A+ by Standard &

Poor's Corporation and Aa by Moody's Investors Service. The major determinant of the Salt River Project's credit rating is its debt service coverage ratio, which is the ratio of revenues available for debt service to the amount needed to pay principal and interest costs on outstanding indebtedness for a given year. Revenues available for debt service are, basically, total operating revenues less operating expenses.

The emphasis on the debt service coverage ratio stems from two factors. First of all, the ratio indicates to creditors the ability of the Salt River Project to generate sufficient revenues to repay its obligations.

Secondly, the debt service coverage ratio reveals how much remains after expenses to be contributed towards construction projects--the size of the

"down payment" which the Salt River Project itself, through its revenues, can actually make towards its loans. This contribution factor is further illustrated by the debt ratio (the amount of assets funded by borrowings).

For the Salt River Project, this ratio is about 84 percent; therefore, only about 16 percent of construction has been financed by ratepayers.

The smaller the contribution by ratepayers, the larger the risk to the creditors (bondholders) of the Salt River Project. The greater the risk, the greater the interest rates demanded by bondholders and the greater the financing costs to be borne by ratepayers in the future. By increasing the contribution of ratepayers, however, the financial standing of the Salt River Project can be kept from a serious deterioration; this will allow continued access to debt at reasonable rates of interest.

In the absence of a rate adjustment, revenues per kwh unit of output are expected to rise by 7.4 percent, while total operating and maintenance expenses per unit are expected to increase by 16.7 percent from fiscal year 1980-1981 to fiscal year 1981-1982. As a consequence, revenues available to pay interest and repay the principal on debt are projected to decline by 4.7 percent on a per-unit basis, while the Salt River Project's total debt service requirements per kwh are expected to rise by 12.2 percent.

result is a The serious decline in the debt service coverage ratio, to 1.38 in anticipated i

fiscal year 1981-1982.

It is the opinion of management that if the debt service coverage ratio were to fall and remain below 1.5, the Salt River Project would lose its present bond rating. If revenues were to fall below 1.35 times debt service requirements, the bond covenants stipulate that the Salt River Project could no longer issue parity revenue bonds. On a long-term basis, the Salt River Project has, established a debt service coverage ratio of 1.70 as a financial ~

goal. The recamnended rate adjustment for fiscal year 1980-1981 of

$ 5,641,000 produces a debt service coverage ratio of 1.66. The adjustment recanmended for fiscal year 1981-1982 of'57,179,000 is required to produce a debt service coverage ratio of 1.70.

The following discussion summarizes management's recommended allocation of the proposed increase among customer classes, proposed changes in specific standard electric rate schedules, and proposed changes in experimental time-of-day rates. These suggested changes are detailed in Section B, which is supplemented by Appendix C, a discussion of the Public Utility Regulatory Policies Act.

Recommended rate increases for each class depend, in part, on rate of return. As seen in the following table, lower returns correspond to higher proposed increases.

1979 Rate of Return by Hajor Customer Class and Proposed Rate Increases for These Classes 1979 Rate of Return Proposed Customer Class On Committed Ca ital Increase Residential 6.8% 14. 2%

Commercial and Small Industrial 8.8% 11.9%

Large Industrial 5. 7% 16.0%

Irrigation Pumping 2. 9% 16.0%

Rate design follows distribution of the rate increase to each class.

Design takes into account present rates, cost trends, and the results of marginal and historical cost studies. This year, both cost studies identify costs by season and by time of day.

It is proposed that qualifying cogenerators:be charged for electric service according to the applicable standard electric rate schedule.

Other proposed changes are as follows.

Rebasin of the Fuel Ad'ustment Revise the amount of fuel cost included in base rates from

$ 0.006089/kwh to $ 0.009758/kwh. This is accomplished by adding the current fuel adjustment factor, $ 0.003669/kwh, which has been in effect for 18 months, to the present base.

E Residential Service

1) Increase the customer charge from $ 2.75 to $ 5.00.

2) Remove one summer rate block leaving a 0-800 kwh block and a block covering all additional kwh above 800 kwh.

3) Remove one winter rate block, leaving a 0-400 kwh block, a 400-800 kwh block and an "all remaining" block.

These block changes are recommended because customer use of 800 kwh is the approximate point at which time-of-day rates become economical.

0 tional Time-of-Da Rate Pro ram--Residential E-80 E-81 Commercial E-32 Authorization exists for a total of 1,000 customers on these experimental rates. Expand the program to a total of 3,000 customers, divided between the residential and commercial classes as customer participation i dictates. Increase summer rates more than winter rates for E-80 Optional Residential Time-of-Day Rate, and E-81 Optional Residential Time-of-Day Rate with Demand. Make E-32 Optional Commercial Time-of-Day Rate available to all E-35 and E-36 customers and eliminate off-peak demand charge.

E-82 0 tional Residential Flat Rate Freeze rate until 1985 when the rate would be eliminated.

E-35 Commercial and Small Industrial Rate General Service)

1) Increase summer rate more than winter.

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2) Increase rate for higher energy-use blocks by a greater percentage than for lower energy-use blocks.

3) Increase minimum bill to $ 8.50.

E Total Electric Schools and Churches Frozen Applies only to existing customers on this rate. Same changes as for E-35. E-36 does not apply a winter demand charge.

Eliminate rate by October 15, 1985, and transfer existing customers to the E-35 General Service Rate or E-32 Time-of-Day Rate.

E Lar e Industrial Service

1) Eliminate first 4 million kwh blocks, off-peak, summer and winter.

2) Increase summer rate more than winter.

E Wind Machines Increase horsepower charge for smaller machines by a greater amount than for larger machines.

E Irri ation Pum in Service

1) Increase summer rate more than winter.

2) Increase minimum bill to $ 8.50.

E-50 E-51 E-52 E-54 E Street and Securit Li htin Service No change in rate form.

C Chilled Water Service Frozen Applies only to existing customers on this rate. No change in rate form.

Riders to Rate Schedules No changes proposed.

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SECTION A FINANCIAL STATEMENT REGARDING PROPOSED RATE INCREASE

'EFFECTIVE MARCH 1, 1981

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INTRODUCTION The Salt River Project, like any other member of the economic community, faces increases in its costs of operation. All of the categories of costs--operating and maintenance expenses, taxes and tax equivalents, and principal and interest on bonds outstanding--are forecasted to increase from levels in the 1980-1981 fiscal year. 1 Increases in expenses occurring more rapidly than increases in revenues exert pressure on the financial performance of the Salt River Project. Stable financial performance allows the Salt River Project continued access to the debt market at reasonable cost. Furthermore, this permits capital costs to be spread over the life of the facilities.

OPERATING AND MAINTENANCE EXPENSES Operating and maintenance expenses include purchases of fuel, manning power stations, maintenance of the electric system and, in general, those costs incurred so that the Salt River project's ratepayers receive energy upon demand. Operating and maintenance expenses can be subdivided into three cost categories: (1) fuel for thermal generation; (2) purchased power; and (3) labor, materials, supplies, and services.

Coal and oil are the primary fuels that the Salt River Project uses in generation. When available, natural gas displaces fuel oil. Without considering the intensity of use of each resource, Chart 1 compares the broad movements in the price of various fuel resources available to the Salt River Project. The chart shows fuel prices per million BTU. (A BTU, British thermal unit, is the standard unit measuring the quantity of heat energy.)

1 The Salt River Project changed its fiscal year from the calendar year to the twelve-month period from May 1 to April 30, effective on May 1, 1980.

CHART 1 COIVlPARATlVE FUEL PRlCES S/Million Btu 7.00 Fuel Oil ¹2 (Distillate) 6.00 5.00

/  %/ 0 e ~ ++ noae Fuel Oil ¹6

{Residual) 4 4.00 I yy y01g ~

.rr~l ~0

. ~ +e 3.00 gre+~Ome r'

~

~0

~ ~0

~~0~

00 ~ ~~ +~

y' ~ .0 ~

~~ ~

~ ' ~ Natura I Gas 2.00 ~~

0~~ ~~

~

~ ~ p~ gl ~ yy ~ .

~~ ~

~

~ ~~ .

rp ~~~ ~rN

~ sSee ~

/ >o

~ ~O~ Newer Coal

~ HSI ~

1.00 Older Coal

0.  ?

EI 0 0 0 1977 1978 1979 1980 NOTE: Older coal refers to coal purchasedunder long-term contracts executed before 1974, while newer coal refers to coal purchased under subsequent contracts.

From January 1977 to September 1980, residual oil prices increased from $ 1.85 to )5.30 per million BTU; since September 1979, prices have increased by 63.6 percent, from $ 3.24 per million BTU. Distillate oil prices per million BTU increased from $ 2.59 in January 1977 to $ 6.40 in September 1980; since September 1979, prices have increased by 9.2 percent, from $ 5.86. Prices for older coal, i.e., coal purchased under long-term contracts executed before 1974, increased from $ 0.24 per million BTU in January 1977 to $ 0.80 in September 1980. Since September 1979, older coal prices have increased 53.8 percent, from $ 0.52. Prices for newer coal (coal purchased under subsequent contracts) are more than double the prices for older coal, with the September 1980 level at $ 1.69 versus $ 0.80 for older coal.

Intensity of use applied to the prices for each fuel resource determines the cost of these fuels to the ratepayer. At each moment in time, that mix of resources with the lowest cost should be used. gable 1 demonstrates that for fiscal year 1979-1980, the Salt River Project utilized the least costly fuel to produce 69 percent of the energy demanded by its customers. Generating units fired by distillate oil provided less than 1 percent while residual oil-fired resources provided over 6 percent.

Table 1 Sources of Energy 1979-1980 Fiscal Year Fuel Percent Hydro 12 Gas 8 Distillate 1 Residual 6 Coal 69 Miscellaneous Purchases 4 100 Salt River Project Agricultural Improvement and Power District, ly SOURCE:

Official Statement, 1980 Series B Revenue Bonds, October 17,1 1980, p. 16, and Power Operations Department, Salt River Project.

For comparison, average fuel prices paid in 1979 by other major electric utilities in Arizona and California are shown on Table 2. The Salt

River Project competes for fuel supplies just as does any other entity in the economic community. Even though the fuel mix and environmental constraints vary between these utilities, the lack of a wide dispersion in average fuel prices for 1979 as seen on Table 2 demonstrates that the Salt River Project is acting reasonably in securing fuel resources.

Table 2 Com arative Avera e Fuel Prices Cents Million BTU 1979

~Ut i it 1 Nuclear Coal Fuel Oil Natural Gas Salt River Project N/A 58 303 185 Arizona Public Service N/A 62 315 205 Pacific Gas and Electric N/A N/A 294 243 Southern California Edison 43 71 340 239 Tucson Electric Power N/A 65 267 228 SOURCE: Arizona Public Service Company-, Statistical Re ort for Financial Anal sis 1969-1979; Securities and Exchange Commission, Form 10-K (Annual Report Pursuant, to Section 13 or 15(d) of the Securities and Exchange Act of 1934) for the Fiscal Year ended December 31, 1979, Pacific Gas and Electric Company, Southern California Edison Company; Tucson Electric Power, Uniform Statistical Re Power 0 erations ort 1979 1979 (Edison Statistical Energy provided from Electric Data.

Institute); Salt River hydroelectric sources (including hydro Project, el purchases) and miscellaneous purchases from other utilities amounted to 16 percent of net production in fiscal year 1979-1980, as shown in Table 1.

Approximately 7 percent of fiscal year 1979-1980 production came from Colorado River hydro purchases made through the Arizona Power Authority and the Western Area Power Administration. The Salt River Project's hydro resources produced an additional 5 percent.

Miscellaneous purchases of power amounting to 4 percent of fiscal year 1979-1980 net production must be viewed as fulfillingthe objectives of others and hence should not be considered as a firm resource. Availability, in amount and time, is at the discretion of the supplier.

1 Labor, materials, supplies and services are those expenses which c be most directly affected by management activity. Management can (1) expand,

maintain or shrink work force size within the bounds of acceptable customer service; (2) bargain with labor; (3) let bids to obtain lowest cost materials and supplies; and (4) oversee services such as customer energy management, customer inquiry and transportation. The category comprising labor, materials, supplies and services usually constitutes 20 to 22 percent of total operating, maintenance, and debt service requirements. Labor costs are a function of wages and salaries paid and the size of the work force. In Phoenix, average hourly earnings of production workers on manufacturing payrolls (used here as an indicator of average wages in the area) increased by 9.6 percent between August of 1979 and August of 1980. In order to maintain its work force, the Salt River Project must pay wages and salaries competitive with prevailing market rates. Thus, labor compensation at the Salt River Project reflects increasing labor costs in the economy. The size of the work force is, of course, the other determinant of total labor costs.

Table 3 presents a comparison of electrical employees at the Salt River Project with two other major Arizona electric utilities. The ratios shown are the number of employees per one thousand customers and per megawatt peak to permit comparison on a similar per-unit basis of output in terms of customers served and capacity provided. As the table shows, the Salt River Project's productivity record, in terms of employees per customer and per unit of power, ranks within the bounds of the other utilities. Vhile there may be obvious reasons for disparity between these entities (such as size of service area, commitment to construction, utilization of contract labor, etc.), the relatively small variance demonstrates that the Salt River Project's management is prudently utilizing its manpower resources.

U. S. Department o'f Labor, Bureau of Labor Statistics. Data obtained from Chase Econometric Associates, Inc., Regional Data Base.

Table 3 Measures of Em lo ee Productivit 1979 Electrical Employees Excludin Power Production Em lo ees Per Thousand Electric Per Megawatt Entit, Customers Year-End Peak 1979 Salt River Project 7.8 1.3 Arizona Public Service 9.7 1.5 Tucson Electric Power 5.5 1.1 SOURCES: SRP - Power Operations and Budget Departments; APS - Statistical Re ort for Financial Anal sis 1969-1979; TEP - Uniform Statistical Re ort 1979.

Material costs, like labor costs, have suffered from inflation.

Table 4 lists indices for electric utility construction costs. The transmission plant index includes such el'ements as towers and fixtures, overhead conductors and devices, and underground conduit. The cost of such items has increased over 9 percent on a compounded annual basis between 1971 and 1980. Distribution plant includes line and pad-mounted transformers and meters installed. These costs have also increased over 9 percent on a compounded annual basis since 1971. Steam generation plant costs have increased by almost 10 percent on an annual compounded basis since 1971.

These costs include various kinds of boiler plant equipment, turbogenerator l

units, and accessory electri'cal equipment. Between July 1979 and July 1980, transmission, distribution, and steam generation plant construction costs increased by 9.4, 5.2, and 8.6 percent, respectively.

l

Table 4 Electric Utilit Construction Costs Indices 1949 = 100 Steam Transmission Distribution Generator Year Plant Plant Plant 1971 253 220 219 1972 258 226 236 1973 279 246 245 1974 342 296 293 1975 409 357 342 1976 438 375 364 1977 470 402 395 1978 474 412 426 1979 512 460 468 1980 560 484 508 SOURCE: Hand Vhitman Index of Public Utilit Construction Costs, Bulletin 112 (advance release), September 10, 1980, and Bulletin 111, April 1980, pp.

29-30. (Plateau Division, Indexes for July 1.)

TAXES AND TAX E UIVALENTS The Salt River Project is the third largest taxpayer in the State of Arizona. These expenses, which become part of the customer's total burden for electric service, are sales taxes, ad valorem taxes for out-of-state properties, payroll taxes, and contributions in lieu of ad valorem taxes in Arizona.

Sales taxes must be collected by the Salt River, project on its retail sales. It must do so at rates set by the State of Arizona and by various political subdivisions within the state. This portion of expenses will increase along with retail sales without any change in the tax rate.

The Salt River Project has properties in New liexico, Colorado and Nevada, on which ad valorem taxes are paid. This category of expenses will grow with the increasing valuation or tax rates applied to existing properties and/or with additional out-of-state properties acquired.

Payroll taxes, both federal and state, are paid by the Salt River Project, just as any other employer. This portion of expenses will grow with increases in employer responsibilities and/or by increases in the number of employees.

Contributions in lieu of ad valorem taxes are, for the Salt River Project, conceptually equivalent to the property taxes paid by other utilities. Table 5 lists 1979 full cash values of broad categories of utilities and mines, with major utilities specified in three categories. The Salt River Project has a greater full cash value than any other single entity, with the exception of Arizona Public Service. Full cash value is only one variable in determining in-lieu taxes actually paid in a year. The assessment ratio and the location of the property are also significant variables. The Salt River Project's assessment ratio, like that of other utilities, is 50 gl percent.

Table 5 Full Cash Value Utilities and Mines 1979 Class Dollars Airline $ 44,400,992 Cable TV 4,011,000 Gas and Electric 2~687>860s500 Arizona Public Service 1 435 000 000

~ ~ ~

Mine 1,011,520,367 Municipal Authority Salt River Project Pipeline Producing Oil and Gas 1,000,000,000 1,000,0001000 282,560,000 2,164,569 l

Railroad 131,075,000 Telephone 1,025,307,500 Mountain States Telephone 860,000,000 Water 66,978,626 SOURCE: Division of Property and Special Taxes, Department of Revenue, State of Arizona, Full Cash Value of Utilities and Mines (June 4, 1979).

Location of the property is critical in determining final taxes paid. For example, Mountain States Telephone and the Salt River Project have roughly similar full cash values and receive the same assessment ratio.

However, Mountain States Telephone pays significantly higher property taxes because its plant and property are located in urban areas. Much of the Salt River'Project's plant and property is located in rural areas of the state.

Large investments in a rural region result in a very low tax rate on property in that region. The local area benefits from the increased tax base and the Salt River Project ratepayers benefit from a lower tax rate.

Contributions in lieu of ad valorem taxes will grow as the value of the Salt River Project's plant grows. Contributions in lieu of ad valorem taxes as a percentage of investors'bondholders and ratepayers) committed capital have varied little over time. The percentages are shown on Table 6 for the ten-year period, 1970 through 1979. This relationship is expected to continue.

Table 6 Contributions In Lieu of Ad Valorem Taxes As a Percenta e of Investors'ommitted Ca ital Year Percent 1970 1.5 1971 1.5 1972 1.4 1973 1.1 1974 1.3 1975 1.6 1976 1.4 1977 1.1 1978 1.0 1979 0.9 SOURCE: Salt River Project, Annual Con troller's Re ort, 1978 and 1979, pp.

42 and 43.

PRINCIPAL AND INTEREST ON BONDS OUTSTANDING A

The last general category of cost is payment of principal and interest on outstanding debt. Specific financial criteria will be described subsequently, but for now it is sufficient to note that inflation has dramatically affected this element of cost also, in two major ways. First, the construction cost of generating and other facilities has outpaced general inflation rates. Second, the cost of debt, as evidenced later in this A

document, has also increased dramatically, along with the general rise in interest rates.

requirements Also, even without additional bonding, continue to rise through 1990.

total debt service l Table 7 shows the debt service requirements on currently outstanding debt (issued through 1980) for the year 1981 through the year 2015 at five-year intervals. Issuing bonds in fiscal year 1980-1981 on which interest must be paid in fiscal year 1981-1982 and in the years following produces even greater revenue requirements and pushes the peak total debt service requirements even further into the future.

3 A general inflation indicator, the Consumer Price Index for Urban Wage Earners and Clerical Workers, has increased at an annual rate of 7.2 percent since 1970 (U. S. Department of Labor, Bureau of Labor Statistics). Steam generation construction costs have increased at an annual rate of 9.5 percent (Hand Whitman Index of Electric Utilit Construction Costs, April 1980, pp.

29 and 30).

A 10

'Table 7 Total Debt Service Requirements As of A ril 30 Year Dollars 1981 $ 151,540,070 1985 158,579,993 1990 160,170,646 1995 155,702,156 2000 148,983,921 2005 147,276,151 2010 145,823,858 2015 119,229,930 SOURCE: Salt River Project Agricultural improvement and Power District, Official Statement, 1980 Series B Revenue Bonds, October 171 1980, p. 26.

PROSPECTIVE PERFORMANCE FOR FISCAL YEAR 1980-1981 AND FISCAL YEAR 1981-1982 WITHOUT RATE ADJUSTMENT Presented on Table 8 are the Salt River Project's prospective cash flow, debt service requirements, and debt service coverage for fiscal years 4

1980-1981 and 1981-1982 without the proposed rate adjustment. All of the figures reflect the most recent information available. The difference between operating revenues and operating expenses is added to interest income and other income to equal revenues that are available for debt service. The debt servi'ce coverage ratio is derived by dividing revenues available for debt service by total debt service requirements. The table is constructed so that one can easily see how the cash flow is forecasted to change from fiscal, year 1980-1981 to fiscal year 1981-1982 without a rate increase.

4 The information is presented both on a dollar basis and on a per-unit basxs.

This is the proper way to isolate increases in specific categories from increases caused by a growth in sales. As the output of any business increases, the cost in various categories required to produce the additional output must also increase. Per-unit figures permit isolation of those categories whose increase deviates from the increase in output.

Table 8 Cash Flow, Debt Service Requirements and Pro Forma Coverage of Debt Service without Proposed Rate Adjustment ($ 000)

Fiscal years ending April 30 (A) (B) (C) . (D) (E)

Pro iected Projected Projected 1980-1981 Projected 1981-1982 1980-1981 Per KWH of 1981-1982 Per KWH of X Change W 0 Increase '80-'81 Ener ~WO I ~81-'82 I 8 8 Sales of Electric Energy - Thousands KWH 11,685,000 11,973,000 Electric Operating Revenues Sales of Energy $ 517,604 $ 571,262 Other Electric Service Revenue 2 976 2 739 Total Operating Revenues 520,580 0.0446 574,001 0.0479 7;4 Operating and Maintenance Expenses Fuel for Thermal Generation 139,102 0.0119 164,610 0.0138 16.0 Purchased Power 18,752 0.0016 22,000 0.0018 12.5 Labor Materials, Supplies 5 Services 101,642 0.0087 125,992 0.0105 20.7 Sales, Ad Valorem 8 Payroll Taxes 26 636 0.0023 29 882 0.0025 8.7 Total Operating 8 Maintenance Expenses 286,132 0. 0245 342,484 0. 0286 16.7 Funds Available from Operations 234,448 0.0201 231,517 0.0193 Interest and Other Income - Net 14 810 0. 0013 11 328 0.0010 Revenues Available for Debt Service 249,258 0.0214 242,845 0.0203 (5.1)

Debt Service Requirements Bond Interest through 1980-1981 131,644 140,995 Bond Principal through 1980-1981 21,655 22,792 Interest 1981-1982 Bond Issues 12 635 Total Debt Service Requirements 153,299 0.0131 176,422 0.0147 12.2 Debt Service Coverage 1.63 1. 38 Balance After Debt Service 95,959 66,423 Investment Earnings - Construction 594 530 Less: In-Lieu of Ad Valorem Taxes 30,372 32,217 Support of Water Operations 13 601 13 750 Funds 1 able for Corporate Purposes 52 5 0.0045 20 986 0.0018 (60.0)

Dollar amounts are listed in columns A (fiscal year 1980-1981) and C (fiscal year 1981-1982) without the recommended rate increase. Corresponding per-unit of output figures are listed in columns B (fiscal year 1980-1981) and D (fiscal year 1981-1982) without the recommended rate increase. Column E lists percent changes in per-unit figures from fiscal year 1980-1981 to fiscal year 1981-1982 without the recommended rate increase.

Sales of electrical energy for the Salt River Project are forecasted to increase 2.5 percent from fiscal year 1980-1981 to fiscal year 1981-1982. 5 This increase in sales, modest by historical standards, is due to the small expected growth in sales from fiscal year 1980-1981 to fiscal year 1981-1982 to residential, commercial, and industrial customers. Furthermore, because of a predicted slow recovery from the current economic recession and greater availability of natural gas, resale and excess sales in fiscal year 1981-1982 are not expected to be as high as those in fiscal year 1980-1981.

In the absence of the recommended rate adjustment, revenues per unit of output are expected to rise by 7.4 percent, while total operating and maintenance expenses are expected to rise by 16.7 percent. The combined cost category, fuel and purchased power, is forecasted to rise by 15.4 percent on a per-unit basis. Increases in this category, as high as they are, are reflected in the fuel adjustment factor and as such are not part of the recommended rate adjustment. The remaining factors, though, do contribute to the need for a rate adjustment.'

Sales of electrical energy consist of two parts--firm and nonfirm excess.

Firm sales are all those sales to customers under a standard electric rate schedule or a contract, whether long-term or short-term. iNonfirm sales are to customers on an as needed/as available basis.

13

Labor, materials, supplies, and services are expected to increase 20.7 percent on a per-unit basis from fiscal year 1980-1981 to fiscal year 1981-1982. While this per-unit increase appears high, there are several factors which must be taken into account in order to isolate the fundamental change in this category. First, this category is lower in fiscal year 1980-1981 by $ 5,095,000,which represents a major reimbursement from participants in the Navajo Generating Station for the Salt River Project's expenses in connection with a major overhaul during fiscal year 1979-1980.

Thus, the base for this category in fiscal year 1980-1981 would have been

$ 0.0091/kwh and the 20.7 percent increase would be reduced to 15.4 percent.

Second, approximately $ 1,200,000 in maintenance work was deferred from fiscal year 1980-1981 to fiscal year 1981-1982. Spreading this increase evenly between the two years would result in raising the category from $ 0.0091/kwh to

$ 0.0092/kwh in fiscal year 1980-1981 and lowering the category from

$ 0.0105/kwh to $ 0.0104/kwh in fiscal year 1981-1982. This lowers the catego increase to 13.6 percent.

Sales, ad valorem, and payroll taxes are expected to increase 8.7 percent from fiscal year 1980-1981 to fiscal year 1981-1982. While sales tax rates have not changed, the category of payroll taxes and out-of-state ad valorem taxes is expected to increase on a dollar basis from fiscal year i 1980-1981 to fiscal year 1981-1982.

As a result, revenues available for debt service, on a per-unit basis, decline 5.1 percent. However, the Salt River Project's total debt

,service requirements per kwh rise 12.2 percent. The debt service coverage ratio, then, is expected to fall to 1.38. Funds available for corporate purposes (the "down payment" provided by revenues) per kwh fall 60 percent from the fiscal year 1980-1981 level, and the debt ratio rises slightly, fro 14

82.74 percent to 82.98 percent. The Salt River Project must avoid this financial trend if it is to hold its credit rating and meet its financial needs.

FINANCIAL CRITERIA The electric utility industry in general invests more money in physical assets to generate a dollar in revenues than any other industry in the economy--the average ratio being about )4.00 of investment in physical plant to each $ 1.00 of annual revenues. This means that, relative to revenues, the electric utility industry must raise more capital--more money--

than any other industry, on average, in order to build the facilities necessary to satisfy the ever-increasing demand for its services, electrical power and energy. As of April 30, 1980, the Salt River Project had $ 4.92 invested in plant for each dollar it generated in electric operating revenues.

Such large financing requirements are one element of the financial risk to which the Salt River Project is subject.

Another element of financial risk is presented by the limited number of financing alternatives available to the Salt River Project. As a municipality, a political subdivision of the, State of Arizona, the Salt River Project is precluded from selling stock to raise money. The Salt River Project has only two basic financing sources: operations (i.e., net revenues generated on the sale of electrical power and energy) or borrowings in the debt markets. The use of debt financing--borrowings--by far outweighs the use of internally generated funds at the Salt River Project. As of April 30, 1980, the Salt River Project was approximately 84 percent debt financed. This is one of the highest proportions of debt financing of any nonjoint action 15

agency utility in the nation (see the Glossary and Note 2-Financial Criteria and Scorecard).

Much in the sense that an individual puts a down payment on a car o r

a home in order to obtain financing for the remainder of the purchase, ratepayers contribute to the financing of the construction of electric plant L

required to satisfy their additional benefit to all demand for power. It is, ratepayers to have the Salt River Project borrow most of of course, its a

t required construction funds, so that the funds may be paid back over time }

as the physical asset purchased is being used.

In general, the greater the down payment on a purchase, the smaller the risk involved for a len'der who funds the remainder of the purchase. The less 'risk involved in a loan, the lower the interest rate. For organizations such as the Salt River Project, the size of the down payment is measured I inversely through the ratio of debt to the total capital committed to the purchase of assets. The size of the down payment is not the only determinan of risk, however.

borrower must No still have matter the how large the ability to pay down payment on a purchase, interest and repay the the principal

)

on whatever size loan is made.

Thus far, the use of a great proportion of debt financing has, in general, worked to the benefit of the Salt River Project and its ratepayers.

The Project has had to provide only a minimal down payment on physical plant; hence, its ratepayers have enjoyed the benefit of spreading the costs of those assets over a great length of time.

Two financial problems have surfaced in recent times, however:

(1) an imbalance between the revenue stream and construction outlays, and (2) an unstable debt market. These problems contribute to the need for an 16

adjustment in rates in order to achieve, at the minimum, a stabilized contribution from revenues relative<to total capitalization.

Energy sales and demand, and thus revenues, have fallen short of earlier projections. This has lessened the need to invest in additional plant facilities. A serious imbalance has developed between the level of capital acquisition and the revenue stream required to provide the down payment and make principal and interest payments on the resultant borrowings. This imbalance impinges upon the credit worthiness of the Salt River Project.

The overall credit worthiness of a borrower of money in the bond markets is measured by the borrower's bond ratings. Salt River Project bonds are rated Aa by Moody's and A+ by Standard and Poor's (see Glossary). In large part, bond ratings determine the marketability (access to the market) and interest cost of the bonds. As detailed in Note 2, the Salt River Project is a weaker credit risk than its direct competitors for debt funds. Specific financial criteria explain why the debt issues of the Salt River Project are viewed as weak; i.e., as compared with three similar utilities, the Salt River Project has the lowest debt service coverage ratio (see Glossary), the highest future burden of financing, the next-to-the-highest debt ratioand the next-to-the-highest amount of revenue bonds outstanding. Only in its operating ratio does the Salt River Project surpass its competition (Note 2)

Viewed in a historical context through the debt service coverage ratio, the debt ratio, and annual interest rates (Charts 2, 3, and 4, respectively), the Salt River Project is seen as a weakening financial entity. 6 Debt service coverage was on a downward trend from 1970 to 1976.

The dashed portion of the lines represents projections for fiscal year 1980-1981 and fiscal year 1981-1982. These projections are detailed in Note 1.

17

CHART 2 ACTUALAND PROJECTED DEBT SERVICE COVERAGE RATIO WITHOUT PROPOSED RATE INCREASE 2.4 8 970 TO 1982 2.2 2.0 P

E R

C 1.8 E

N T

1.6 1.4 1.2 1971 1972 1973 1974 19 976 1977 1978 1979 1980 1981

HART 3 l3EBT RATlO ACTUAL AND PROJECTED 90.0 1970 TO 1982 87.5 85.0 4~

~

S~ ~~aea 82.5 P

so.o R

C.

E 77.5 T

75.0 72.5 70.0 67.5 65.0 1971 1972 1973 1974 1975 1976 1977 1878 1979 1989 1981

'CHART 4 AVERAGE ANNUALINTEREST RATE ACTUAL AND PROJECTED 7.0 1970 TO j982 r- r rrr r r 6.5 6.0 P

E R

C 5.5 E

N T

5.0

" QQ QgP ggj73 ~74~1 Qgg 19+~ 1g Q9 ~+80 A+98

Dependence on debt financing rose rapidly. Interest costs also rose substantially. However, more recently,"'as evidenced in Charts 2 and 3, financial trends have begun to stabilize. While this improvement is principally a result of a relatively stable economic period from 1977 through 1979, the adoption and pursuit by management of the 1.70 debt service coverage ratio as a financial goal are also factors.

The 1.70 debt service coverage goal was selected for three reasons.

First, a 1.70 level for this ratio is within a reasonable range of what other issuers of long-term tax-exempt revenue bonds offer potential investors (see Note 2), Second, the 1.70 level will lead to a reduction in the Salt River Project's dependence on debt financing. Third, the 1.70 level, as a goal, lends confidence that outside sources of variability in the Salt River Project's financial performance will not, in any one year, cause an extreme decline in credit worthiness (see Note 4-Statistics). Unexpectedly low levels of debt service coverage could impinge upon covenants (promises) made by the Salt River Proj ect to its bondholders concerning the security of their investment. One such covenant is'hat in order to issue parity revenue bonds, the debt service coverage ratio must remain above 1.35 in a given year. Thus, if coverage should ever fall below 1,35, only much more expensive financing options would be available to the Salt River Project.

Viewed prospectively, without a rate increase the Salt River Project's financial condition weakens. The debt service coverage ratio (Chart

2) is expected to decline, and the debt ratio (Chart 3) is anticipated to fall and then rise somewhat (refer to Note 1 for details). For fiscal year 1980-1981, in the absence of a rate adjustment, debt service coverage declines only moderately to 1.63, while the debt ratio is expected to improve. This improvement in the debt ratio is due to the institution of a commercial paper 21

program in fiscal year 1980-1981. Commercial paper is a form of short-term borrowing which allows the Salt River Project to lower its short-term borrowing costs and significantly extend the amount of credit available for use. However, short-term borrowing tends to restrict liquidity because of a short repayment schedule. Also, the commercial paper program will have its greatest impact, in terms of offsetting long-term bond issues, in fiscal year 1980-1981. In fiscal year 1981-1982, the continued imbalance between the revenue stream and the existing construction program causes the debt service coverage ratio to drop significantly and the debt ratio to rise slightly.

The second major problem is the recent instability of the debt market. The important question now for a large borrower of funds is not so much the level of interest rates, but if funds will be available to borrow, and on what terms. This instability poses a serious problem for the Salt R iver Project since its dependence on the debt markets has been far greater than its dependence on the ratepayer for capital.

Just as inflation has affected operating expenses, it has produced higher interest rates and, even more recently, has begun to produce unstable long-term markets. In previous years, funds were available to those who wanted to borrow at interest rates that were reasonable and upon terms which were standard and stable. Today, and prospectively, however, interest rates are not only significantly higher but also significantly more volatile. Chart 5 illustrates the behavior of two municipal bond indexes. Also shown on Chart 5 are four bond sales by the Salt River Project. While the interest rates received by these issues closely track the two indexes, all three indicators exhibit instability. This instability prompts behavioral changes in those demanding funds (borrowers) as well as those supplying funds (lenders).

Lenders tend to put their funds in short-term issues, where preservation of 22

MUNICIPALBOND YIELDS II . SALOMON BROTHERS AA ELECTRIC REVENUE BOND iNDEX, BOND BUYER INDEX and SALT RIVER PROJECT BONDS l ~

~

IO ll( /

P E 9 I I R l C I l (A

F I I N

ji T

r i->> - SALOMON BROS. AA BOND BUYER INDEX SALT RIVER PROJECT BOND ISSUES (coupon rate paid on 40-year new issues.)

E M A M J J A S 0 N D J F M A M J J A 8 0 N 1979 'I 980

capital is more assured. Therefore, long-term bond issues are not only a matter of cost but whether the market can be accessed.

Charts 6 and 7 display an indicator of these debt market changes.

The indicator is municipal bond yields contrasted by rating, AA versus A, for two years, 1979 and 1980. Normally, as interest rates rise, the quality differential (interest rate difference) between lower quality (A rated) and higher quality (AA rated) bonds widens. There has been no such increase in this differential for 1980.

Chart 8 displays another indicator of debt market changes, an electric revenue bond index of AA rated bonds as a,.percentage of 30-year United States Treasury bonds'ax-exempt bond yields have increased substantially as a proportion of Treasury bond yields. Whereas in 1979 the Salomon Brothers AA bond index averaged about 75 percent of the 30-year U. S.

Treasury bond yield, throughout 1980 it has averaged in excess of 80 percent of that yield.

These trends have two roots. First, as there is only a limited amount of money available to be borrowed, that money tends to be rationed overE the demand for it. Highest quality credit risks get money first, then lesser quality credit risks, and so on. Many of the lower quality borrowers in the marketplace this year have been unable to borrow for one reason or another, so their influence is not being as strongly felt by the indices. This is one reason for the lack of significant quality differentials in bond yields.

Second, institutional investors--such as insurance companies, bond funds and banks--have been unwilling or unable to invest in the long-term market throughout most of 1980. These are the most sophisticated investors in the marketplace, and tend to draw finer quality distinctions among borrowers. To replace institutional lenders, the market has had to turn to retail lenders--

24

0 0 CHART 6 RECENT TRENDS IN MUNICIPALBOND YIELDS 8.4 1979 e/$

I 8.0 l<- < iX I

P E V.6 I R SALOMON BROS. AA ELEC. REV. BOND INDEX C SALOMON BROS. A ELEC. REV. BOND INDEX I E

N I T l J

7.2

~ ~ jeW r~

%~0~1>> ~

p I I

6.8 l

I I-o~y ~~~o~e~o J 64 A 8

CHART 7 l0.5 RECENT TRENDS IN MUNICIPALBOND YIELDS 1980 I~

1

)1 IO.O ',- I I \ r'i 9.5 / i l

/

I

/

P I F 9.0 I l

R C I lA l E I 8.5 l.

~I

/ l I

~

/ P.

I l J

8.0 %1' l j ti li 7.5 7.0 SALOMON BROS. AA ELEC. REY. BOND INDEX SALOMON BROS. A ELEC. REV. BOND INDEX J F M A J J A S 0 1980

0 0 CHART 8 0 g5 SALOMON BROTHERS AA ELECTRIC REVENUE BOND INDEX AS A PERCENT OF. 30-YEAR U.S. TREASURY BONDS 0.80 P

E R

0.75 N

T 0.70 0.65 J F M A M J J A S 0 N O J F M A M J J A 8 0 N l979 l980

smaller companies and individuals. It takes higher levels of interest rates to attract the retail lender--hence the proportionate rise against taxable bonds--and the retail lender tends to make lesser quality distinctions than the institutional lender.

There are two other trends that have developed in the long-term markets that cannot be illustrated by charts, but that are of particulari note in assessing the financing risk of the Salt River Project. Inflation has so decimated the effective return to lenders in the debt markets that lenders are increasingly unwilling to buy 40-year bonds, preferring instead, shorter maturities, such as 20 years. This is particularly true of the institutional investor. It is very likely that the day will come when 40-year bonds cannot be sold, as the risk of loss of return due to inflation becomes too high. For

/N borrowers such as the Salt River Project, the effect of this will be similar to cutting the term of a mortgage in half, i.e., the monthly payments will become very high. Also, the use of variable-race bonds is gaining acceptanc as a means of long-term financing while preserving the capital of the lender.

This is a growing technique in the mortgage market, also. The primary difficulty of variable-rate securities is that businesses cannot plan on what their financing costs are going to be. Additionally, for the Salt River Project, it is not at, all clear that variable-rate revenue bonds could be issued under the existing resolutions governing the issuance of revenue bonds.

Financial risk for the Salt River Project is higher than in recent years and will grow with increases in inflation. Thus, the Salt River Project must seek to preserve its credit worthiness by retaining its bond ratings.

Management has embodied this effort in the 1.70 debt service coverage ratio. i A good credit rating should insure continued access to the debt markets to

,support the Salt River Project's construction commitments at reasonable rates 28

The proposed rate adjustment supports the goal of the 1.70 debt service coverage ratio for fiscal year 1981-1982 and hence is the key element in retaining the financial health of the Salt River Proj ect. Another important element involves balancing the revenue stream and construction outlays through the maximization of sales of nonfirm excess energy and a sale of part of the ownership of the Palo Verde Nuclear Generating Station.

PROSPECTIVE PERFORMANCE FOR FISCAL YEAR 1980"1981 AND FISCAL YEAR 1981-1982 WITH RATE ADJUSTMENT Table 9 specifies the prospective results for fiscal year 1980-1981 and fiscal year 1981-1982 with a rate adjustment in effect. The magnitude of the proposed rate adjustment is $ 57,179,000,which would produce a 1.70 debt service coverage ratio in fiscal year 1981-1982. As a result, the debt ratio should decrease to 81.39 percent from 82.56 percent and there should be

'e $ 78,165,000 electrical in funds available for corporate purpose.

Because of slower-than-expected growth rates in power and energy, the Salt River Project demand has excess for generating capacity--currently and prospectively. The excess capacity has resulted in management's commitment to two courses of action.

First, the Salt River Project is actively seeking to sell as much excess energy as possible in the nonfirm excess energy market. For fiscal year 1981-1982, excess sales, both firm and nonfirm, to neighboring utilities of 1.23 billion kwh (approximately 10 percent of total energy sales) have been budgeted. Excess revenues from such sales defray a portion of fixed expenses faced by customers served under standard electric rate schedules. While these excess sales are a significant part of total sales, any additional sales which produce reasonable excess revenues can only be made within the constraints of the Salt River Project electric system and its points of interconnection with 29

Table 9 Cash Flow, Debt Service Requirements and Pro Forma Coverage of Debt Service with Proposed Rate Adjustment ($ 000)

Fiscal years ending April 30 (A) (B) (c) (D) (E)

Projected Projected Projected 1980-1981 Projected 1981-1982 1980-1981 Per KHH of 1981-1982 Per KHH of X Change Wl '80-'81 Ener CW1 ~81 '82 8 8 8

. Sales of Electric Energy - Thousands KHH 11,685,000 11,973,000 Electric Operating Revenues Sales of Energy $ 523,521 $ 631,237 Other Electric Service Revenue 2 976 2 739 Total Operating Revenues 526,497 0.0451 633,976 0.0529 17.3 Operating and Maintenance Expenses Fuel for Thermal Generation 139,102 0.0119 164,610 0.0138 16.0 Purchased Power 18,752 0.0016 22,000 0.0018 12.5 Labor Materials, Supplies 8 Services 101,642 0.0087 125,992 0.0105 20.7 Sales, Ad Valorem 5 Payroll Taxes 26 912 0.0023 32 678 0.0027 21.7 g Total Operating and Maintenance Expenses 286,408 0.0245 345,280 0.0288 17.6 Funds Available from Operations 240,089 0.0206 288,676 0.0241 Interest and Other Income - Net 14 810 0.0013 ll 328 0.0010 Revenues Available for Debt Service 254,899 0.0219 300,024 0.0251 14.6 Debt:Service Requirements Bond Interest through 1980-1981 131,644 140,995 Bond Principal through 1980-1981 21,655 22,792 Interest 1981-82 Bond Issues 12 635 Total Debt Service Requirements 153,299 0.0131 176,422 0.0147 12. 2 Debt Service Coverage 1.66 1. 70 Balance After Debt Service 101,600 123,602 Investment Earnings - Construction 594 530 Less: In-Lieu of Ad Valorem Taxes 30,372 32,217 Support of Hater Operations 13 601 13 750 Funds ai lable for Corporate Purposes 58 2 0.0050 $ 78 165 0.0065 30.0

other utilities, In addition to technical factors, economic factors also limit the magnitude of excess sales. The current economic recession and an expected sluggish recovery imply that the demand for excess power and energy will decrease. Greater-than-expected supplies of natural gas available for boiler fuel also lessen the likelihood of other utilities making nonfirm excess purchases. Nevertheless, excess sales with reasonable excess revenue margins should contribute positively to fiscal year 1981-1982 results.

Second, even though fuel costs associated with the Palo Verde Nuclear Generating Station are expected to be lower than average fuel costs on the system, immediate capital requirements are problematic. Consequently, the Salt River Project is seeking to sell 25 percent of its ownership share in the Palo Verde Nuclear Generating Station. Such a sale, when made, would (1) lower the amount of subsequent construction funds required from the Salt River

'e Project system and (2) lower total debt service requirements, fuel costs in the future than otherwise would have but (3) impose higher been the case.

Within the bounds of the financial terms acceptable to the Salt River Project, which include a reasonable sales price, a sale of 25 percent of I Salt River Project's share in the Palo Verde Nuclear Generating Station will significantly reduce the growth rate in total debt service requirements, thereby lowering the growth in revenue requirements, Because of the uncertainty involved in a sale of this magnitude and the market created by others selling excess capacity, management is recommending an adjustment in rates which does not include the projected financial effects of such a sale.

Upon the completion of a sale of 25 percent of the Salt River Project's ownership share in the Palo Verde Nuclear Generating Station, management will subsequently review and recommend either of two actions: (1) a separate rate 31

.adjustment process to reflect lower revenue requirements due to such a sale, or (2) significant postponement of any pending rate adjustment processes.

the Currently, distribution of management is seeking approval of a rate adjustment, the rate adjustment over the customer classes, and the

)

electric rate schedules to effect this adjustment, summarized as follows:

Mana ement's Recommendation Ad ustment Fiscal Year Fiscal Year roval Sou ht 1980-1981 1980-1981 Amount $ 57,179,000 $ 5,641,000 Distribution to Customer Classes Residential $ 30,665,000 $ 2,871,000 Commercial and Small Industrial 16,495,000 1,484,000 Large Industrial 8,275,000 979,000 Irrigation Pumping 1,152,000 2379000 Wind Machine Street/Security Lighting Electric Rate Schedules 38,000 554,000 See Section B 8,000 62,000 gl Implementation Date March 1, 1981 Implementation of the proposed adjustment on March 1, 1981, will amend the projected results for fiscal year 1980-1981 the debt service coverage ratio rises from 1.63 without the proposed adjustment to 1.66 with the proposed adjustment. Because of the voluntary wage and price guidelines which existed at the time, management recanmended a 1.64 debt service coverage ratio as the goal for fiscal year 1980-1981 during the rate adjustment process in January 1980. 7 This one-time deviation from the long-term goal of a 1.70 7

As obtained from inquiries to the Utility Division of the Council on Wage and Price Stability, the Council on-Wage and Price Stability is in the process of re-evaluating its program. However, using the gross margin standard for public utilities and the most recent amendments thereto, management believes that the Salt River Project could qualify for a rate L adjustment of 28.9 percent.

32

debt service coverage ratio was approved as embodied in the now existent standard electric rate schedules. To secure the desired level in the debt I

service coverage goal for fiscal year 1980-1981 and to demonstrate financial stability, management recommends implementation of the proposed adjustment on March 1, 1981. Since the adoption of 1.70 as a debt service coverage goal in 1978, the Salt River Project has shown and, with the proposed rate adjustment, should show the following key indicators to the financial community:

Debt Service Year Debt Ratio Calendar 1978 1.65 85.69 1979 1.73 83.54 Fiscal 1979-1980 1.70 84.24 1980-1981 1.66* 82.56*

1981-1982 1.70* 81.39*

• Projected 33

34 SECTION B MANAGEMENT'S RECOMMENDATION FOR REVISING STANDARD ELECTRIC RATE SCHEDULES

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INTRODUCTXON This section contains management's recommendation for revising specific standard electric rate'chedules to implement a proposed $ 5,641,000 increase in revenues for fiscal year 1980-1981, and a $ 57,179,000 increase for fiscal year 1981-1982.

The first step in rate design is to allocate the proposed increase in revenues to each customer class. The next step is to modify each standard electric rate schedule using results of cost studies and following principles of good rate design.

Several tables are included that summarize the studies and show the effects of past rate changes. Then, general rate design is discussed and is followed by a summary of the rate design revisions proposed. Rate changes and comparisons for each rate category follow in independent sections.

Optional time-of-day rates for residential customers are described following the E-23 residential rate. E-32, the optional time-of-day rate for commercial customers, follows the E-36 rate.

Note that cogeneration and small power production rates, rates proposed to be paid by the Salt River Project to qualified cogenerators under 100 kw, are covered in separate documents.

Because it is proposed .that, applicable standard electric rate schedules, the rate change proposals contained herein also pertain to sales to cogenerators.

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36 RESULTS OF COST STUDIES AND PROPOSED INCREASE BY CUSTOMER CLASS Two major cost studies guide Salt River Project electric rate design. This year both studies show costs by time of day. The first, a time-differentiated historical cost allocation (TDHCA), develops a rate of return on committed capital for the Salt River Project electric system and for each electric customer class. Revenues are actual 1979 revenues, and expenses are average costs for each time period of that year, summer and winter, on-peak and off-peak. Previously, expenses were average costs for the entire year.

The second study, a time-differentiated marginal cost allocation (TDMC) focuses on what the cost to the Salt River Project would be if customer load during each time period of the year increased or decreased by a small amount.

Marginal costs may be above or below average costs. They are an important rate making guide because, when possible, rates are set so that no one pays less for energy than the cost to produce it, and when less energy is used, customer savings are at least as great as the savings to the Salt River Project for not producing it. Copies of these studies are available for review in the rate information room.

Historical Cost Stud The results of the TDHCA include cost breakdowns by demand in each period (cost/kw), by energy in each period (cost/kwh), and by customer.

Referring to Table 1, summer demand costs are seen to vary from $ 11.20 to

$ 35.38/kw. Demand costs in other periods are significantly lower. Energy costs in each period are similar for all classes except sales for resale, which is higher in cost since sales to most of these customers are made from the more expensive generating units. Customer costs are $ 5,280/year for large 37

TABLE 1 Pro Forma Allocation of Costs to Various Customer Classes Summer Winter On-Peak ff-Peak On-Peak ~ Off-Peak Annual Customer ~Cost KM ~Cost KMH ~Cost KW ~Cost KMH Sales for Resale Production Costs $ 22.31 $ 0.0227 $ 0.07 $ 0.0140 $ 4.09 $ 0.0187 $ 2.46 $ 0.0125 $ 0.01 71 $ 5,280 Large Industrial 27.13 0.0181 0.08 0.0143 4.92 0.0138 2.96 0.0125 0.0145 5,280 Eastern Area Hines 28.21 0.0182 0.08 0.0144 5.21 0.0139 3.09 0.0126 0.0145 5,280 Distribution System Customers Residential 11.20 0.0190 1.28 0.0152 3.46 0.0147 1.96 0.0134 0.0160 53.31 oo --Coamerci al 15.36 0.0187 1.27 0.0149 2.72 0.0144 1.11 0.0131 0.0154 53.31 Agricultural Pumping 28.69 0.0188 2.38 0.0150 8.21 0.0145 1.94 0.0132 0.0157 '3.31 Salt River Pro]ect Pumps 35.38 0.0202 6.98 0.0163 14.09 0.0158 3.71 0.0145 0.0168 53.31 SOURCE: 1979 Tim Differentiated Historical Cost Allocation Study (TNCA).

industrial and mining customers and $ 53.31/year for all distribution system customers.

Table 2 shows return figures by class. Industrial, agricultural pumping and miscellaneous customer classes are seen to be below average return while the residential customer class is slightly above, and the commercial customer class is 2.4 percent above average.

Salt River Project pumps are owned and- operated by the Salt River Project while agricultural pumping is the retail pumping class. I Revenue allocation and rate design are based on the retail class.

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The eastern area continues to have a poor return on committed capital because special contracts still exist for a few customers in the area.

Two major special contracts expire in early 1981, and the two remaining contracts will expire by 1990. In accordance with the policy, adopted by the Board of Directors on August 14, 1975, of maximizing revenues obtained from special contract customers whenever legally possible, these special contract customers will be converted to standardized rate schedules when their contracts expire. Whenever possible, the Salt River Project has taken steps to increase revenues from those customers whose special contracts are not subject to termination. For instance, special contract customers will pay higher rates in 1981 through the fidel and labor escalation provisions of their contracts, 39.

I Table 1979 Pro-Forma 2

Return on Committed Capital by Customer Class I

1979 HCA Return on I

Committed Ca ital Sales for Resale (Production) 9.4%

Large Industrial 5.7 Eastern Area Mines (0.8)

Distribution System Customers

- Residential 6.8

- Commercial and Small Industrial 8.8

- Agricultural Pumping 2.9

- Salt River Project Pumps 1.0

- Miscellaneous ~O. 6 Overall 6.4%

SOURCE: 1979 Time Differentiated Historical Cost Allocation Stud TDHCA Mar inal Cost Stud The marginal cost study, TDMC, results include cost allocation by demand in the winter and summer peak periods (cost/kw), by energy in each of the four annual periods (cost/kwh), and by customer. Marginal energy costs are higher in each period than average energy costs because more expensive generating units are used to produce marginal or "extra" energy.

Table 3 summarizes results, by customer class, for the 1980 marginal cost study. Energy costs are similar for each class. Demand costs reflect metered demand, noncoincident with system peak. They vary from $ 8.28/kw for the residential customer class to $ 14.80 for the pumping customer class.

Customer costs are $ 127.80/year for residential and commercial customers and

$ 6,880.30 for large industrial customers.

The marginal cost of generation is set at zero for this study, resulting in a substantial decrease in the marginal cost of capacity (cost/kw). This result is a direct consequence of the Salt River Project's current excess generating capacity situation The capacity charge recognizes 40

the cost implications of increases or decreases in system kw demand.

Increases in de'mand are easily met with existing excess capacity, while decreases in demand have been determined to have no effect on costs. Thus, customer demand changes have no effect on the marginal cost of generation, at least for the conditions evaluated in this study.

Table 3 Results of 1980 Marginal Cost Study Annual Customer Cost Summer Vinter (Dollars per Residential Service from Distribution S stem Demand-related cost ($ /kw) 8.28 .24 127.80 Energy cost (cents/kwh) 4.68 2.22 2.29 1.70 Commercial & Small Industrial Service from Distribution S stem Demand-related ($ /kw) 10.12 .24 127.80 Energy cost (cents/kwh) '.68 2.22 2.29 1.70 Agricultural Pumping Service from Distribution S stem Demand-related cost ($ /kw) 14.80 ,42 127.80 Energy cost (cents/kwh) 4.68 2.22 2.29 1.70 Large Industrial Service (Valle Transmission Demand-related cost ($ /kw) 12.04 .29 6,880.30 Energy cost (cents/kwh) 4.57 2.14 2.29 1.69 SOURCE: 1980 Time 'Differentiated Mar inal Cost Stud Pro osed Rate Increase b Customer Class The historical cost study, TDHCA, is the principal study used for allocating rate increases among customer classes. The allocation recommended also is supported by the results of, the TDMC study. Table 4 shows the rate of return by class for four years. Note that allocation of 1979 costs by time of 41.

i day and season did not cause extreme changes in the rates of return of the t

classes.

Rate Table 4 of Return (%) on Committed Capital by Class I

for Major Retail Customer Classes 1976-1979 Commercial &, Valley Large 'Agricultural Residential Small Industrial Overall 1976 6.3 7.6 0.0 (1. 1) ~

4.3 1977 8.7 10.5 1.8 1~4 7.0 1978 6.8 8.0 5.3 0.8 5.7 1979 6.8 8.8 5.7 2.9 6.4 SOURCE: Historical Cost Allocations Studies for 1976-1979.

The rates of return shown in Table 4 are recalculated as changes from the average rate of return'n each year and graphed in Figure 1. This comparison method shows the results of past rate increases on class returns.

Pumping and large industrial classes rec'eived above average increases, causing their returns to rise toward the average. Residential and commercial class returns have declined toward the average through generally lower rate increases.

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FIGURE '1 Comparison of Relative Rates of Return on Committed Capital by Customer Class 1976-1979 Commercial and Small Industrial Overall Average  % 76 77 78 Residential 79 Large. Industr'ial

-2, Pumping Table 5 compares 1979 revenues to costs for each customer class developed in the TDHC marginal cost study (Table 3). Although not dixectly comparable to Table 4 historical returns, comparison of marginal cost recovery also identifies the commercial and small industrial class as above average.

These results supplement the TDHCA results used to determine the proposed revenue increases by customer class.

Table 5 Ratio of 1979 Class Revenue to 1980 Harginal Cost for Major Retail Customer Classes Commercial & Valley Large Agricultural Overall 1.10 1.33 1.04 0.99 1.16 Using rate of return as a guide, rate levels can be adjusted so that each customer class pays approximately its cost. of electric service. Cost studies should be used for guidance and as a tool in rate design as customer class rates of return cannot be expected to be exactly equal. Differences occur because costs and loads are not static but change over time. Thus, 43

average returns will be corrected since Salt River Project policy continues t be that each class should pay its cost of service.

Both the trends in rates of return (Figure 1) and the ratios of revenues to marginal cost (Table 5) indicate the same order for allocation of the revenue increase to customer classes.

1. The commercial and small industrial class shows the highest rate of return and the highest ratio of revenues to marginal costs. Thus, the 1 commercial and small industrial class would receive the lowest increase. Even though costs are expected to increase substantially in 1981, this class would likely continue to return an above average amount without taking some measure to reduce its rates relative to other classes. Some judgment is exercised in deciding how much lower than other customer class, increases this class increase should be. Too high an increase will not accomplish the goal of bringing rate of return closer to the average, while too low an increase wil place an excessive burden on other classes. The proposed increase of 11.9 percent, 1.8 percent below average, balances both concerns.

2. The residential class is next highest in rate of return and in ratio of revenues to marginal costs. It is proposed that this class be increased by 14.2 percent, 0.5 percent above average. Again, judgment is required because the residential class is the largest customer class, accounting for over half the Salt River Project's total retail electric revenue. Too high an increase would draw rate of return above average and reduce the burden on other classes excessively. Too low an increase would place too great a burden on other classes.

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3. The lar'ge':~industrial class is third in order of, rate of'eturn L

and in ratio of revenue to marginal cost.

l percent above average, A 16 is proposed for this class presented for the commercial and residential classes.

percent rate increase, 2.3 based on the same reasoning

4. An above average increase of 16 percent also is proposed for the agricultural pumping class. This class showed the lowest rate of return and the lowest ratio of revenues to marginal costs of the four major classes.

5. The wind machine class was not specifically studied this year for its relative cost recovery. An average increase of 13.7 percent is proposed for this class.

6. Street and security lighting falls in the miscellaneous class which showed a rate of return of -0.6 percent in 1979 (Table 2). An above average increase of 16 percent also is proposed for this class.

In summary, management believes that the increases shown in Table 6 represent a fair allocation of the required $ 5,641,000 and $ 57,179,000 among the customer classes. Note that the proposed allocations for fiscal year 1980-1981 are estimates based on the aggregate allocations proposed for fiscal year 1981-1982. No attempt was made to simulate revenues for the individual months of March and April, 1981.

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Table 6 Proposed Increased Revenues by Customer Class Fiscal Year 1980-1981 Fiscal Year 1981-1982 Proposed Increase March 1981-April 1981 May 1981-April 1982 in Electric Revenue Without Sales Tax. 5 641 000 $ 57 179 000

% Increase  % Increase Class in Revenues in Revenues Residential $ 2,871,000 14.2 $ 30,665,000 14.2 Commercial 6 Small Industrial 1,484,000 10.8 16,495,000 ll. 9 Large Industrial 979,000 12. 2 8,275,000 16.0 Irrigation Pumping 237,000 15. 3 1,152,000 16.0 Wind Machines 8,000 14.5 38,000 13.7 Street & Security Lighting 62 000 15.9 554 000 16.0 Overall $ 5,641,000 12.8 $ 57,179,000 13.7 L

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RATE DESIGN After the proposed revenue increase has been allocated to the customer classes, existing rates are reviewed by comparing current rate structures with the results of the two cost studies, TDHCA and TDMC, and cost trends. Table 7 shows the changes for the residential customer class in marginal costs (TDMC) for 1976, 1978, 1979 and 1980. Average costs (TDHCA) by time period are shown this year for. the first time. Both studies characterize the summer on-peak period as the most costly, while winter on-peak is lower in cost, and off"peak, summer and winter, is the lowest cost period. Because energy costs are averaged, the TDHCA study indicates a small variation in energy costs among periods, 1.34 cents/kwh to 1.90 cents/kwh. Marginal energy costs vary from a low of 1,69 cents/kwh to a high of 4.68 cents/kwh.

These time-differentiated costs are applied to typical customer energy use patterns to calculate the relative cost recovery within a class. A cost analysis accompanies each proposed change in standard electric rate schedules in the following sections.

Rate design is not influenced solely by costs. One cost study may show a drastic, change in winter costs, for example, implying that all winter rates should be revised. lf implemented, such a change could cause serious disruptions to the customers whose homes or businesses are affected. Thus, rate stability is an important concern in rate design. Other areas for concern are:

improving customer understanding of rates; producing the proper amount of revenue with stability; administering new rates or rate structures; and avoiding discrimination among customers within a rate class.

These areas for concern are taken into account in preparation of the rate revisions proposed on the following pages. Also, potential effects of the Public Utility Regulatory Policies Act are discussed in Appendix C. I g

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TABLE 7 Marginal and Average Cost By Period - Residential Customer Class Summer Winter

$ /KW 4/KWH $ /KW 4/KWH Demand Ener Demand Ener On Peak Off Peak On Peak Off Peak On Peak Off Peak On Peak Off Peak TDMC 1976 55. 76 0.00 2.34 0.69 10.81 0.00 1.07 0.51 TDMC 1978 24.84 0.00 3.21 2.03 2.15 0.00 2.24 1.64 TDMC 1979 26.89 -

0.00 4'.38 1.89 2.15* 0.00~ 2.97* 1.85*

TDMC 1980 8.28 0.00 4.68 2.22 0.24 0.00 2.29 1.70 Change, 1976-1980 (85.1$ ) OX 100.0X 221.7$ (97.8X) OX 114.0X 233.3X TDHCA 1979 1. 28 1. 98 1. 53 3. 46 1. 96 1. 47 1.34

• Peak hours changed from 10:00 a.m. - 10:00 p.m. to 7:00 a.m. - 10:00 p.m.

SOURCES: 1976, 1978, 1979 and 1980 Time Differentiated Marginal Cost Studies and 1979 Time;Differentiated Historical Cost Allocation Study.

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SUMMARY

OF PROPOSED RATE REVISIONS Significant changes proposed in standard electric rate schedule forms are summarized below. Details of proposed fuel adjustment rebasing and analysis of proposed changes in individual rate schedules follow in the next.

sections.

Note on Co eneration and Small Power Customer Char es It is proposed that qualifying cogenerators and small power electric rate schedule.

Rebasin of the Fuel Ad'ustment It is proposed to revise the amount of fuel cost included in base rates from $ 0.006089/kwh to $ 0.009758/kwh. This is accomplished by adding the current fuel adjustment factor, $ 0.003669/kwh, which has been in effect for 18 months, to the present base of $ 0.006089/kwh.

E Residential Service

1) Increase the customer charge from $ 2.75 to $ 5.00.

2) Remove one summer rate block leaving a 0-800 kwh block and a block covering all additional kwh above 800 kwh.

3) Remove one winter rate block, leaving a 0-400 kwh block, a 400-800 kwh block, and a block covering all additional kwh above 800 kwh.

Block changes are recommended because customer use of 800 kwh signifies the approximate point above which time-of-day rates become economical.

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Authorization currently exists for a total of 1,000 customers on these experimental rates. Expand the program to a total of 3,000 customers, divided between the residential and commercial classes as customer L

participation dictates.

E 0 tional Residential Time-of-Da Rate Increase summer rate more than winter rate.

E-81 - 0 tional Residential Time-of-Da Rate with Demand Increase summer rate more than winter rate ~

E 0 tional Residential Flat Rate No change in rate form. Propose freezing rate until 1985 when it would be eliminated.

E 0 tional Commercial Time-of-Da Rate 1) 2)

Propose making Off-peak E Commercial and Small available to demand charge all eliminated.

Industrial Service E-35 and E-36 customers.

General Service el

1) Increase summer rate more than winter rate.

2) Increase rate for higher energy use blocks by a greater percentage than for lower energy use blocks.

3) Increase minimum bill to $ 8.50.

E Total Electric Schools and Churches Frozen Applies only to existing customers on this rate. changes as i

i Same for E-35. E-36 does not apply a winter demand charge.

Recommend that this rate be eliminated by October 15, 1985 and that existing customers transfer to the E-35 General Service Rate or E-32 Time-of-Day Rate.

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E Lar e Industrial Service

1) Eliminate first 4 million kwh blocks, off-peak, summer and winter.

2) Increase summer rate more than winter.

E Wind Machines Increase horsepower charge for smaller machines by a greater amount than for larger machines.

E Irri ation Pum in Service

1) Increase summer rate more than winter.

2) 1'ncrease minimum bill to $ 8.50.

E-50 E-51 E-52 E-54 E Street and Securit Li htin Service No change in rate form.

C Chilled Water Service Frozen Applies only to existing customers on this rate. No change in rate form.

Riders to Rate Schedules No changes proposed.

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54 REBASING OF THE FUEL ADJUSTMENT The standard electric rate schedule .fuel adjustment clause provides for increases or decreases in standard electric rate schedules when the average cost of fuel and purchased power increases or decreases. Since July 1

of 1979, the cost of fuel and purchased power has been averaging $ 0.009758 per kwh. This amount has been included in the energy rate for all'standard electric rate schedules. The base amount of $ 0.006089 per kwh is included in the rate. The difference, $ 0.003669/kwh, termed fuel adjustment factor, is added to each energy rate. The fuel adjustment factor is merely the difference between average fuel and purchased power cost and the amount included in the rate. It can be either a positive or a negative number.

It is proposed to rebase the fuel adjustment by adding the current

$ 0.003669/kwh to the base amount included in the rate. This means that a new base of $ 0.009758/kwh would be included in each energy rate and that the fuel adjustment factor would be zero until a variance from the base amount occurs.

Future changes in average fuel and purchased power costs would be reflected in positive or negative adjustments from $ 0.009758/kwh. Figure 2 shows the effect of this change graphically.

Rebasing the average cost-of fuel will result in standard electric rate schedules that more accurately reflect the actual rate charged. Rebasing has no effect on customer bills.

1 In March 1980, after following statutory procedures for change in standard electric rate schedules, the Board of Directors of the Salt River Project removed several fixed expenses from fuel costs subject to escalation. This reduced average cost by about 0.9 mills/kwh.

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FIGURE 2 Fuel Cost/KMH and Fuel Adjustment Amounts Base Fuel 8 Purchased Power Amount Adjustment Factor x Actual Fuel 5 Purchased Power Cost Budget (anticipated) Fuel 5 Purchased Power Cost

$ .016

$ .014

$ .012 x x Fc

$ . 010 x-----x--x X

x x .003669

$ .008 x Fuel Adjustaant x Factor ,X

$ .006 x

xl

$ 0.009758/kwh Proposed Base

$ .004 0.006089 Base Fuel 8 Purchased Power Amount

$ .002 1979 1980 1981 SOURCE: Accounting Records, Rates and Corporate Economics Departm'nt.

PROPOSED CHANGES IN STANDARD ELECTRIC RATE SCHEDULES J

Cost analysis and rate changes. for each proposed standard electric rate schedule follow in this section. The present fuel adjustment of

$ 0,003669/kwh has been included in all present rates, proposed rates and rate

'comparisons.

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58 E"23 RESIDENTIAL ELECTRIC SERVICE In the Salt River Project area there are over,290,000 residential customers being served on the E-23 residential standard electric rate schedule. In 1979, these customers accounted for 34.5 percent of all energy sold, and 43.9 percent of all revenues collected by the Salt River Project.

For the fiscal year 1981-1982, residential sales are forecasted at over. four billion kwh.

The residential customer class consists of a very diverse group of customers. While annual consumption averaged approximately 13,000 kwh in 1979, consumption ranged from less than 100 kwh to more than 10,000 kwh per month. Conservation, size of residence, types of appliances and other energy sources available are just a few of the variables that determine individual customer usage.

For 1981, the proposed average increase of 14.2 percent for residential customers is slightly above the overall proposed rate increase of 13.7 percent for standard electric rate schedule customers.

The percentage increase has been applied evenly between the summer and winter seasons. Although the relationship between marginal costs and.

current revenues in Figure 3 would indicate that more revenues should be added to the summer than the winter period, management has concluded that the- large bills that could be generated in the summer months by this course of action, the adverse impacts on customer budgets, and the potential decrease in the summer revenues require continuation of the present summer/winter rate differential.

59

FIGURE 3 MARGINAL COST AND CURRENT REVENUE BY KQl S

100 HINTER Current Revenue (E-23)

Harglnal Costs (ZOS Load Factor)

"I 600 12 15 1800 2100 2400 2700 KN S

150 SUHHER 125 Harglnal Costs (20T Load Factor) 100 75 50 25 600 1200 1500 1800 2100 2400 2700 60

E-23 Revenue Recove as a Percenta e of 1979 Historical and 1980 Mar inal Costs " Table 8 The comparison of current revenues with costs derived from the 1979 TDHCA study for ten customer use patterns, show a greater percentage recovery of these costs for the smaller users. Percent recovery of marginal cost varies with load factor and amount of on-peak energy use. These cost studies suggest that relatively poor load factors and a larger proportion 6f on-peak usage result in higher costs to serve.

The proposed increase in this standard electric rate schedule is 14.2 percent with the summer and winter seasons receiving the same percentage increase. The high-usage customer is proposed to receive an above average rate increase. It is proposed that low-usage customers generally receive average or below average increases. The proposed increase is apportioned in the following manner (as shown in Tables 9 to 12).

1) The customer charge is proposed to be increased to reflect the results of the TDMC and TDHCA studies.

2) The 800 kwh level is proposed as the end of the first block in the summer and the second block in the winter. It reflects the approximate energy use where time-of-day rates become a. cost effective alternative to the current E-23 rate.

3) In the summer period,'wo blocks are proposed. In the first block, 0-800 kwh, lower use customers are proposed to receive less than a 14.2 percent average rate increase. Bills with usage at the end of this rate block are proposed to receive the average rate increase of 14.2 percent.

The second block in the summer is the all additional kwh block.

Proposed percentage increases tend to decline to slightly below average up to 1,500 kwh then begin to increase as usage levels increase. See Table 10.

61.

4) In the winter period, two 400 kwh blocks are proposed to provide a relatively smooth transition. Customer bills between 200 and 400 kwh are proposed to increase from 12 to 17 percent in the winter period. Customer bills with usage falling in the second 400 kwh block are proposed to receive a winter increase of approximately 16 percent. For usage above 800 kwh, bills are proposed to increase from 12 to 17 percent. See Table 11.

Table 9 compares the proposed E-23 rate with the current E-23 rate for each season. Tables 10 and 11 compare revenues with the current E-23 rate to revenues derived from the proposed rate by usage level in each season.

Table 12 compares the proposed E-23 rate with the current E-23 rate for ten typical pattern customers.

I' 62

TABLE 8 REVENUE RECOVERY AS A PERCENTAGE OF 1979 HISTORICAL AND 1980 MARGINAL COSTS Maximum Load Present Annual Annual Recovery Recovery .

Custom r KM Factor Revenue Marginal TDHCA as a X of as a X of Pattern Annual KWH ~Jun-Se t ~Recover Cost Cost Mar inal Costs TDHCA Costs Rl 3,964 1.2 37. 7 $ 298. 15 $ 248. 80 $ 161. 26 - 119.84 184.89 R2 4,962 1.5 37. 8 349.59 278.97 187.10 125.31 186.85 R3 9,130 3.9 26. 7 538.31 406.98 331. 35 132.27 162.46 R4 11,170 9.0 -14. 2 664. 17 542.40 549.20 122.45 120. 93 R5 12,878 11.1 13. 2 746.69 612. 66 636.19 121. 88 117. 37 R6 14,886 12. 5 13. 6 836.81 702.06 738. 58 119. 19 113. 30 R7 16,642 10.3 18. 4 845.90 663.82 703. 38 127. 43 120.26 R8 18,588 13. 6 15.6 917.07 746.48 832.66 122.85 110.14 R9 19,522 15.4 14.5 967.93 788.69 883.34 122.73 109.58 Rl 0 20,947 7.1 33.7 1,047.11 800.98 646.09 130.80 162.16 SOURCE: Rates and Corporate Economics Department.

TABLE 9 E-23 RESIDENTIAL ELECTRIC SERVICE SUNNER (NAY 15-OCTOBER 14)

Eave.mzu.

$ 5,00/MONTH CUSTOMER CHARGE 0,0677/KWH FIRST 800 KWH 0,0596/KwH ALL ADDITIONAL Burner

'$2,75/MONTH CUSTOMER CHARGE 0.071069/KwH FIRST 300 KWH 0, 055169/KwH NEXT 1500 KWH 0, 047169/KwH ALL ADDITIONAL HINTER (OCTOBER 15-t'1AY 14)

BKLQSED

$ 5i00/MONTH CUSTOMER CHARGE 0,0664/KwH FIRST 400 KWH 0,0443/KwH NEXT 400 KWH 0,0324/KwH ALL ADDITIONAL PJKKKI

$ 2.75/MONTH CUSTOMER CHARGE 0,067669/KwH FIRsT 300 KWH 0,039269/KwH NEXT 400 KWH 0,033769/KWH NEXT 500 KWH 0,026069/KWH ALL ADDITIONAL 64

TABLE 10 E-23 RESIDENTIAL ELECTRIC SERVICE SUNNER RATE CONPARISON (NAY 15-OCTOBER 14)

QH EBEKHI Bmznszn 100 $. 9,86 $ 11,77 $ 1,91 19,37 200 16, 96 18,54 1,58 9,32 i ~00 29,59 32.08 2,49 8,42 600 40. 62 45,62 5,00 12,31 800 51,66 59,16 7,50 14,52 i 1,OOO 1,200 62,69 73,72 71,08 83,00 8,39 9,28 13,38 12,59 i 1,SOO 90,27 100,88 10,61 11,75 12,40 116,26 130,68 14,42 I 2 ooo 2,500 139,84 160,48 20,64 14,76 s,ooo 163,43 190,28 26,85 16,43 g

4,000 210,60 2L>9.88 39,28 18, 65

TABLE 11 E-23 RES IDENTIAL ELECTRIC SERVICE WINTER RATE COMPARISON (OCTOBFR 15-MAY 14)

KHH mPmmz 100 $ 9,52 $ u,64 2,12 22,27 200 16,28 18,28 2,00 12,29 400 26,98 31,56 4,58 16,98 600 34.83 40,42 5,59 16,05 800 42,14 49,28 7,14 16,94 1,000 48,89 55,76 6,87 14,05 1,200 55.64 62,24 6,60 11.86 1,500 63,46 71,96 8,50 13,39 2,000 76,50 88,16 11,66 15,24 2,500 89,53 104,36 14,83 16,56 3,000 102,57 120,56 17,99 17,54 4,000 128,64 152,96 24.32 18,91 r

r 66 l

TABLE 12 PATTERN CUSTOMER ANNUAL BILL COMPARISONS Proposed Pattern Annual Present Proposed Percent Custorrer KMH SRP SRP Increase R1 3,964 $ 298. 15 $ 325. 78 9.27 R2 4,962 349.59 390.45 11. 69 R3 9, 130 538. 31 615. 29 14. 30 R4 11,170 664. 17 755.61 13. 77 R5 12,878 746.69 848. 66 13. 66 R6 14,880 836.81 956.92 14. 35 R7 16,642 845.90 963. 26 13. 87 18,588 917.07 1,038. 43 13. 23 19,522 967. 93 1, 100.61 13. 71 R10 20,487 1,047. 71 1, 193. 55 13. 92 67

68 EXPERIMENTAI" RESIDENTIAL RATES Salt River Project currently offers the following experimental residential rates as alternatives to E-23:

1) E-80, a time-of-day rate,

2) E-81, a time-of-day rate with demand'charges, and

3) E-82, a flat rate (i.e., characterized by the absence of declining energy blocks).

All of these experimental rates are voluntary.

The Salt River Project has contracted with customers on these rates to maintain schedule availability through February 28, 1985 with the stipulation that prices, terms and conditions are subject to change.

Time-of-day rates reflect changes in cost over the customer load cycle. As demand for electricity increases during daylight hours, more expensive generating units must be activiated. Those hours in which the demand for and cost of electricity are relatively high are known as on-peak hours. Conversely, those hours in which the demand for and cost of electricity are relatively low are known as off-peak hours. Vith the technology available to meter electricity by on-peak and off-peak periods, electric utilities can offer rates which reflect these time related cost changes.

Customers on time-of-day rates who shift consumption of electricity from on-peak to off-peak hours may realize a savings in their electric bills.

This shifting may, over time, flatten out daily load curves, facilitating reduced operation of more expensive oil fired peaking units and greater reliance on lower cost coal-fired base load units. The savings associated with such developments would flow as nearly as possible through the time-of-69

clearly is in line with a commitment to have prices reflect costs.

Approximately 300 customers have elected service under experimental residential time-of-day rates as of November 6, 1980. More than 90 percent of these customers selected E-80, time-of-day rate without a demand charge.

For 1980, availability of schedules E-80 and E-81 is limited to 1,000 customers collectively. A change is proposed to allow a total of 3,000 customers on time-of-day rates, allocated between residential and commercial c ustomer classes as customer participation dictates.

The residential time-of-day rate increase proposed is 14.2 percent overall, resulting from a 15.9 percent increase in the summer season cost and 12.0 percent increase in the winter season. Increasing the summer/winter differential permits closer tracking of costs and provides greater potential for winter savings from load shifting.

Through an oversight, customers participating in this experimental program are prohibited from switching between the E-80 rate and the E-81 rate without first returning to the standard E-23 rate for one year. It is proposed that customers be permitted to change to the other time-of-day rate if they find that the one they originally selected is not suitable. However, once a change is made, the customer would be barred from returning to the first rate for one year. The cost of implementing this proposed change is expected to be negligible.

70

E-80 RESIDENTIAL TIME-OF-DAY RATE WITHOUT DEMAND CHARGES E-80 Pro osed Rates The 14.2 percent proposed increase produces only minor changes in rate structure. The following summarizes Table 13.

1) The monthly customer charge is proposed to be maintained at

$ 15.00/month. This charge continues to reflect marginal costs for customer-related distribution facilities, time-of-day metering equipment, and time-of-day billing procedures.

2) The on-peak/off-peak differential is proposed to be maintained at 3-to-1 during the summer season, and increased from 2-to-1 to 2.5-to-l during the winter season to provide greater incentive for load shifting.,

3) No change is proposed in the on-peak and off-peak hours.

4) It is proposed to increase the summer rate more than the winter rate.

E-80 Winter and Summer Rate Com arisons It is proposed that large-use customers receive a greater increase than small use customers thereby enabling E-80 to track E-23 over a wide range of usage. As seen in Table 14, the range of increase is proposed to be.0.0 percent 'to 16.5 percent in the winter season and 0.0 percent to 18.2 percent in the summer season.

One of the objectives of good rate design is the achievement of a smooth transition. That is, rate changes should not be so severe as to cause undue hardship for any group of customers. The $ 15.00/month customer charge effectively precludes customers with usage below 400 kwh from electing service under this rate. Therefore, the effective range of increase in the winter is 71

8.5 percent to 16.5 percent. Since no E-80 customer would receive an increase more than 1.4 times greater than the proposed average increase, the objective of smooth transition would be achieved.

E-80 Bill Com arisons b T e of Customer Table 15 compares electric bills computed with the proposed E-80 rate with those computed with the current E-80 rate as well as with the proposed E-23 rate. Comparisons are made for ten typical customer usage patterns. As seen in the table, the greater the annual usage, the greater the proposed annual percentage increase. Also seen is the close tracking of E-80 with E-23 for all but pattern 1, the lowest usage pattern.

E>>80 Potential Savin s indicate, for the winter Tables 16 and 17 respectively, proposed E-23 bills for and summer seasons various monthly usage levels. Also i shown are the corresponding proposed E-80 bills'nd potential savings assuming different on-peak consumption percentages. The lower the on-peak consumptio percentage, the greater the potential monthly savings with E-80.

The estimated residential class average on-peak consumption percentage for the summer season is 65 percent. At this percentage, customers E-80 't with monthly usage at or 50 to E-23 at or above 1,600 kwh would save by above monthly usage of 600 kwh.

switching from E-23 to percent on-peak, customers would achieve savings on E-80 relative Last summer, E-80 customers averaged less than 50 percent consumption on-peak.

The estimated residential class on-peak consumption percentage for the winter season is 52 percent. At this percentage, savings would be achieved on the proposed rate E-80 rate relative to the proposed E-23 rate for monthly usage between 400 kwh and 1,600 kwh. Such consumption is typical of I

72

customers with gas and electric energy homes. At 37 percent on-peak, E-80 produces savings for monthly usage at or above 400 kwh and 2,500 kwh.

1 73

TABLE 13 E-80 Proposed Residential Tim.-of-Day Rate Wi thout Demand Charge Winter (October 15 - May 14)

~Pro osed

$ 15.00/Month Customer Charge

$ 0.0526/Kwh, On-Peak

$ 0.0210/Kwh, Off-Peak Peak Hours: 7 a.m. - 10 p.m., Monday - Friday All other hours off-peak Present

$ 15.00/Month Customer. Charge

$ 0.041669/Kwh, On-Peak

$ 0.020669/Kwh, Off-Peak Peak Hours: 7 a.m. - 10 p.m., Monday - Friday All other hours off-peak Summer (May 15 - October 14)

~Pro osed

$ 15.00/Month Customer Charge

$ 0.0745/Kwh, On-Peak

$ 0.0250/Kwh, Off-Peak Peak Hours: 10 a.m. - 10 p.m., Monday - Sunday All other hours off-peak Present

$ 15.00/Month Customer Charge

$ 0.062369/Kwh, On-Peak

$ 0.020669/Kwh, Off-Peak Peak Hours: 10 a.m. - 10 p.m., Monday - Sunday All other hours off-peak 74

TABLE 14 E-80 PROPOSED PERCENTAGE INCREASES AT VARIOUS USAGE LEVELS Minter Summer 52K On-Peak 65K On-Peak Proposed Present Percentage Proposed Present Percentage E-80 E-80 Increase E-80 E-80 Increase KNH 0 $ 15. 00 $ 15.00 0. OX $ 15.00 $ 15.00 0.0X 100 18. 74 18.16 3.2 20.72 19. 78 4.8 200 22.49 21. 32 5.5 26.43 24.55 7.7 400 29.97 27.64 8.4 37.87 34.11 11.0 600 37.46 33. 95 10. 3 49.30 43.66 12.9 800 44.95 40.27 11.6 60.74 53.22 14.1 1,000 52.43 46.59 12. 5 72.18 62.77 15.0 1,200 59.92 52.91- 13.2 83.61 72.33 15.6 1,400 67.40 59.22 13. 8 95.04 81. 88 16.1 1,600 74. 89 65.54 14. 3 106.48 91. 44 16.4 1,800 82. 38 71. 86 14.6 117.92 100.99 16. 8 2,000 89. 86 78.18 14.9 129.35 110.55 17.0 2,500 108.58 93. 97 15.5 157.94 134.44 17.5 3,000 127. 30 109.77 16.0 186.52 158. 32 17. 8 3,500 146.01 125.56- 16. 3 215.11 182. 21 18.1 4,000 164.73 141. 36 16.5 243.70 206.'lO 18. 2

TABLE 15 COMPARISON OF PROPOSED E-80 WITH PRESENT E-80 AND WITH PROPOSED E-23 FOR TEN CUSTOMER PATTERNS Customer KWH KWH Proposed Present Percentage Proposed Percentage Pattern On-'Peak Off-Peak E-80 E-80 Increase E-23 E-80 > E-23 1 2,097 1,867 $ 358.17 $ 330. 03 8.5 $ 325. 78 9.9 2 2,801 2,162 408.73 371. 74 10.0 390.45 4.7 3 5,294 3,836 604.72 536. 58 12.7 615. 29 (i.7) 4 7,008 4,162 746.17 652. 92 14.3 755. 61 (i.2) 5 8,442 4,436. 853.52 743.13 14.9 848. 66 0.6 6 9,771 5,109 960.59 832.63 15.4 956.92 0.4 7 9,538 7,104 944.98 821. 63 15.0 963.26 (>.9) 8 12,136 6,452 1,085.74 934. 97 16.1 1,038. 43 4.6 9 11,573 7,949 1,109.69 962.00 15.4 1,100.61 0.8 10 12,527 7,970 1,182.82 1,018.40 16.1 1,193. 55 0.9

gg W W W W. W gQ M M 0 0 TABLE 16

CO>)PARISON OF PROPOSED E-80 WITH PROPOSED E-23 FOR VARIOUS USAGE LEVELS WINTER Proposed Proposed Proposed E-80 f-80 E-80 E-80 KWH E-23 52%%d On-Peak Savings 37K On-Peak Savings 0 5.00 $ 15.00 $ 15.00 100 11.64 18.74 18.27 200 18. 28 22.49 21.54 400 31. 56 29.97 1.59 28.08 3.48 600 40.42 37.46 2.96 34.62 5.80 800 49.28 44.95 4.33 41.15 8.13 1,000 55.76 52.43 3.33 47.69 8.07 1,200 62.24 59.92 2.32 54 '3 8.01 1,400 68. 72 67.40 1.32 60.77 7.95 1,600 75. 20 74.39 0. 31 67.31 7.89 1,800 81. 68 82.38 73.85 7.88 2,000 88. 16 89.86 80.38 7.78 2,500 104.36 108.58 96.73 7.63 3,000 120.56 127.30 113.08 7.48 3,500 136,76 146.01 129.42 7.34 4,000 152.96 164.73 145.77 7.19

TABLE 17 COMPARISON OF PROPOSED E-80 WITH PROPOSED E-23 FOR VARIOUS USAGE LEVELS SUMMER Proposed Proposed Proposed E-80 E-80 E-80 E-80 KWH E-23 65K On-Peak ~Savin s 50% On-Peak ~Savin s 0 $ 500 $ 15.00 $ 15.00 100 11.77 20. 72 19.97 200 18.54 26.43 24.95 400 32.08 37. 87 34.90 600 45.62 49. 30 44.85 $ 0.77 800 59.16 60.74 54.80 4.36 1,000 71.08 72.18 64.75 6.33 1,200 83.00 83. 61 74.70 8. 30 1,400 94.92 95.04 84.65 10.27 1,600 106. 84 106. 48 $ .36 94.60 12.24 1,800 118.76 117. 92 .84 104.55 14. 21 2,000 130.68 129.35 1. 33 114.50 16.18 2,500 160.48 157.94 2.54 139.38 21.10 3,000 190. 28 186.52 3.76 164.25 26.03 3,500 220.08 215. 11 4.97 189.12 30.96 4,000 249.88 243.70 6.18 214.00 35.88

E-81 RESIDENTIAL TIME-OF"DAY RATE WITH DEMAND CHARGES E-81 Pro osed Rate The proposed rate increase for E-81, as for E-80, is 14.2 percent.

The following summarizes the rates shown in Table 18.

1) The monthly customer charge is proposed to be maintained at

$ 15.00/month. This charge continues to reflect marginal costs for'customer-related distribution facilities, time-of-day metering equipment, and time-of-day billing procedures.

2) On-peak demand charges are proposed to increase 42 percent in the summer and 60 percent in the winter to align them more closely with demand charges in industrial and commercial time-of-day rates.

3) The on-peak/off-peak differential in energy charges is proposed to increase to 1.75 in the winter season to provide greater incentive for load shifting.

4) No change was made in the on-peak and off-peak hours.

5) Summer rates are proposed to increase more than winter rates.

E-81 Winter and Summer Rate Com arisons For this proposal, large-use customers receive a greater increase than.small-use customers, thereby enabling E-81 to track E-80 and. E-23 over a wide range of usage. Table 19 indicates the proposed percentage increase by usage level assuming estimated class average on-peak load factors of 30 percent in the winter and 40 percent in the summer. The range of increase proposed is 0.0 percent to 16.6 percent in the winter season and 0.0 percent to 18.2 percent in the summer season, almost identical to the increases proposed for the E-80 rate.

79

E-81 Bill Com arisons b T e of Customer

)

Table 20 compares electric bills computed with the proposed E-81 rate with those computed with the current E-81 rate as well as with the proposed E-23 rate. Comparisons are made for ten typical customer usage patterns as developed through limited load research. As seen, in general, large-use customers are proposed to receive greater increases than small-use customers. E-81 tracks E-23 but not as closely as does E-80, because the use of both energy and demand charges creates somewhat higher bills relative to E-23 for these customers with low load factors.

E-81 Potential Savin s Tables 21 and 22 indicate, for the winter and summer seasons respectively, proposed E-23 bills for various monthly usage levels. Also shown are the proposed E-81 on-peak consumption percentages bills and potential savings assuming different, and on-peak load factors. The lower the i

on-peak consumption percentage and the higher the on-peak load factor, the greater the monthly savings with E-81 relative to E-23. Potential savings are greater with E-81 than with E-80 owing to the opportunity to control demand as well as energy usage.

As mentioned previously, the estimated summer average on-peak i

consumption percentage is 65 percent. The estimated average summer on-peak load factor is 40 percent. Customers with these characteristics and with monthly usage at or above 1,600 kwh would save by switching from E-23 to E-81.

At 50 percent on-peak consumption with a 40 percent load factor, savings would occur at or above 600 kwh.

The estimated residential class on-peak consumption percentage for the winter season is 52 percent. The estimated winter average load factor is t

80

30 percent. With these characteristics, savings occur for customers with monthly usage between 400 and 1,400 kwh. However, at 37 percent on-peak and a 30 or 40 percent load factor, savings occur at 400 kwh/month and above. The potential range of usage over which savings can occur is greater during the winter season on E-81 than on E-80.

81

TILE 1G E-81 Proposed Residential Time-of-.Day Rate with Demand Charge Winter (October 15 - May 14)

~Pro osed

$ 15.00/Month Customer Charge

$ 0. 0368/Kwh, On-Peak

$ 1.60/Kw, On-Peak

$ '0.0210/Kwh, Off-Peak Peak Hours: 7 a.m. - 10 p.m., Monday - Friday All other hours off-peak Pr esent

$ 15. 00/Month Customer Charge

$ 0.031869/Kwh, On-Peak

$ 1.00/Kw, On-Peak

$ 0.020669/Kwh, Off-Peak Peak Hours: 7 a.m. - 10 p.m., Monday - Friday All other hours off-peak Summer (May 15 - October 14)

~Pro osed

$ 15.00/Month Customer Charge

$ 0.0527/Kwh, On-Peak

$ 3.20/Kw, On-Peak

$ 0.0250/Kwh, Off-Peak Peak Hours: 10 a.m. - 10 p.m., Monday - Sunday All other hours off-peak Present

$ 15.00/Month Customer Charge

$ 0.047069/Kwh, On-Peak

$ 2.25/Kw, Off-Peak

$ 0.020669/Kwh, Off-Peak Peak Hours: 10 a.m. - 10 p.m., Monday - Sunday All other hours off-peak

TABLE 19 E-81 PROPOSED PERCENTAGE INCREASES AT VARIOUS USAGE LEVELS Minter Summer 52K On Peak 30K Load Factor 65K On Peak 40K Load Factor Proposed Present Percentage Proposed Present Percentage E-81 E-81 Increase E-81 E-81 Increase 0 $ 15.00 $ 15.00 0.0Ã $ 15.00 $ 15.00 O.OX 100 18.77 18.18 3.2 20. 73 19.78 4.8 200 22.55 21. 36 5.6 26.45 24.57 7.7 400 30.09 27. 73 8.5 37.90 34.14 11.0 600 37.64 34.09 10.4 49.35 43.71 12.9 800 45.18 40.45 11.7 60.80 53. 28 14.1 1,000 52.73 46.82 12.6 72.25 62. 85 15.0 1,200 60.27 53.18 13.3 83.70 72.42 15.6 1,400 67.82 59.54 13.9 95.15 81.98 16.1 1,600 75.36 65.90 14.4 106.60 91.55 16. 4 1,800 82.91 7.2-27 14.7 118.05 101.12 16.7 2,000 90. 45 78. 63 15.0 129.50 110.69 17.0 2,500 109.31 94.54 15.6 158.13 134.62 17.5 3,000 128.18 110.45 16.1 186. 75 158.54 17. 8 3,500 147.04 126. 35 16.4 215. 38 182.46 18.0 4,000 165.90 142.26 16.6 244.01 206.38 18. 2

TABLE 20 COMPARISON OF PROPOSED E-81 WITH PRESENT E-81 AND WITH PROPOSED E-23 FOR TEN CUSTOMER PATTERNS Customer KWH KWH Proposed Present Percentage Proposed Percentage Pattern On-Peak Off-Peak E-81 E-81 Increase E-23 E-8 > E-23 1 2,097 1,867 $ 344.91 $ 321. 24 7.4 $ 325.78 5.9 2 2,801 2,162 387.31 357.64 8.3 390.54 (0.8) 3 5,294 3,836 574.90 516.78 11.2 615.29 (6.6) 4 7,008 4,162 762.99 664.97 14. 7 755.61 1.0 5 8,442 4,436 859.31 747.36 15.0 848.66 1.3 6 9,771 5,109 989.76 852.68 16.1 956.92 3.4 7 9,538 7,104 1,012.72 866.89 16.8 963.26 5.1 8 12,136 6,452 1,132.57 967.70 17.0 1,038. 43 9.1 9 11,573 7,949 1,141.08 983.39 16.0 1,100.61 3.7 10 12,527 7,970 1,082.93 951.64 13.8 1,193.55 (9.3)

TABLE 21 COMPARISON OF PROPOSED E-81 WITH PROPOSED E-23 FOR VARIOUS USAGE LEVELS WINTER Proposed E-Sl Proposed E-81 Proposed E-81, Proposed 52% On-Peak E-81 37K On-Peak E-81 37% On-Peak E-81 KWH E-23 30K Load Factor ~Savin s 30$ Load Factor ~Savin s 40% Load Factor ~Savin s 0 $ 5.00 $ 15.00 $ 15.00 $ 15.00 100 11.64 18.77 18. 29 18.14 200 18.28 22.55 21.58 21.28 4.01 400 31.56 30.09 1.47 28.16 3.40 27. 55 6.59 600 40.42 37.64 2.78 34.74 5.68 33.83 9.17 g . 800 49.28 45.18 4.10 41.32 7. 96 40.11 9.37 1,000 55.76 52.73 3.03 47.90 7.86 46.39 9.58-1,200 62.24 60.27 1.97 54.48 7.76 52.66 9.78 1,400 68. 72 67.82 0. 90 61.06 7.66 '58.94 9.98 1,600 75.20 75.36 67.64 7.56 65.22 10.18 1,800 81. 68 82.91 74.22 7.46 71.50 10.39 2,000 88.16 90.45 80.80 7.36 77.77 10.89 2,500 104. 36 109.31 97.25 7.11 93.47 '1.40 3,000 120.56 128. 18 113.70 6.86 109.16 11.90 3,500 136.76 147.04 . 130.15 6.61 124.86 12.41 4,000 152.96 165.90 146.60 6.36 140.55

TABLE 22 CONPARISON OF PROPOSED E-81. WITH PROPOSED E-23 FOR VARIOUS USAGE LEVELS SUNNER Proposed E-81 Proposed E-81 Proposed E-81 Proposed .65% .On-Peak E-81 50K On-Peak E-81 50K On-Peak E-81 KWH E-23 40$ Load Factor ~Savin s 40% Load Factor ~Savin s 50K Load Factor ~Savin s 0 $ 5.00 $ 15. 00 $ 15.00 $ 15.00 100 11.77 20.73 19.98 19. 76 200 18. 54 26.45 24.96 24.52 400 32.08 37.90 34.92 34. 05 600 45. 62 49.35 44. 89 $ 0.73 43. 57 $ 2.05 g 800 59.16 60.80 54. 85 4. 31 53. 09 6.07 1,000 71.08 72.25 64. 81 6.27 62. 62 8. 46 1,200 83. 00 83.70 74.77 8. 23 72.14 10. 86 1,400 94. 92 95.15 84.73 10.19 81. 66 13. 26 1,600 106. 84 106.60 $.0. 24 94.69 12.15 91.19 15. 65 1,800 118.76 118.05 0.71 104.66 14.10 100. 71 18.05 2,000 130.68 129.50 1.18 114. 62 16.06 110.23 20.45 2,500 160.48 158. 13 2.35 139.52 20.96 134. 04 26.44 3,000 190.28 186. 75 3. 53 164.43 25. 85 157. 85 32. 43 3,500 220. 08 215.38 4. 70 189.33 30. 75 181. 66 38. 42 4,000 249.88 244. 01 5. 87 214. 24 35. 64 205.47 44. 41

E-82 'RESIDENTEAL FLAT RATE Flat rates, characterized by the absence of declining energy blocks, eliminate a price incentive to increase consumption arising from low energy charges in the end blocks. Likewise, customers with high usage will have an incentive to reduce consumption because a reduction usage coupled with a flat energy charge. should result in dollar savings, more proportionate to energy conserved.

Twelve customers have elected service under E"82 as of November 6, 1980. For 1980, availability of this schedule was limited to 2,000 customers.

For 1981, it is proposed that this rate be "frozen" to new customers to minimize customer confusion in the marketing of the residential time-of-day rates. The rate would then be eliminated in 1985 upon the expiration of agreements between customers and the Salt River Project. Additionally, it is proposed that existing customers on E-82 be permitted to transfer to E-80 or E-81 voluntarily without the one year wait currently required.

E-82 Pro osed Rate The rate increase'-proposed for E-82 is 14.2 percent, the same increase proposed for E-23. The summer and winter seasons," are proposed to be given the same increase. As shown in Table. 23, the customer charge is proposed to remain at $ 15.00/month. This permits E-82 to track E-23. The full amount of the proposed increase in the summer and winter seasons is therefore reflected in the energy charge.

E-82 Winter and Summer Rate Com arisons With this proposal, large-use customers would receive a greater increase than small-use customers to permit E-82 to track E-23. As seen in Table 24, the range of proposed increases is 0.0 percent to 19.5 percent in 87

the winter season and 0.0 percent to 16.1 percent in the summer. The percentage increases proposed for average summer and winter usage levels are comparable. The effective range of percentage proposed increases is such so 1

that no one E-82 customer is proposed to receive an increase more than 1.2 times greater than the average. Hence, the rate increase provides a smooth transition in the tracking of E-23.

E-82 Bill Com arisons b T e of Customer Table 25 compares electric bills computed with the proposed E-82 k

rate with those computed with the current E-82 rate as well as with the proposed E-23 rate. Comparisons are made for ten typical customer usage patterns as developed through limited load research. As shown in the table, the greater the proposed annual usage, the greater the annual percentage increase. Also evident is the very close tracking of E-80 with E-23 for all L but customer patter'ns 1 and 2.

E-82 Potential Savin s Table 26 indicates, for both the winter and summer seasons, E-23 bills for various monthly usage levels. Also shown are the E-82 bills and any savings; In the winter season, customers with monthly usage between 400 kwh and 1,400 kwh would benefit under E-82. In the summer season, customers with monthly usage at or above, 3,000 kwh would benefit. The windows for savings on E-82 are significantly narrower than previously flattening in E-23. However, the penalties for owing to the general usage outside these windows i

are not severe. Additionally, because of the reduced potential for savings, existing E-82 customers, under this proposal,, could transfer to other experimental rates without the otherwise required one year wait. It is proposed that E-82 customers be permitted to return to E-23 at any time as well.

88

TABLE 25 E-82 RESIDENTIAL FLAT RATE SUNNER (NAY 15 OCTOBER 14)

PROPOSED

$ 15,00/NORTH CUSTOf'IER CHARGE

$ 0,0584/OH PRESENT

$ 15,00/NONTH CVSTONER CHARGE

$ 0.049769/KMH HIidTER (OCTOBER 15 - [~iAY 14)

PROPOSED

$ 15,00/NONTH CUSTONER CHARGE

$ 0,0581/OH PRESENT

$ 15,00/NORTH CUSTONER CHARGE

$ 0,051269/OH L

~

)0 i 89

TABLE 24 E-82 PERCENTAGE INCREASES AT VARIOUS USAGE LEVELS Minte'r Summer Proposed Present Percentage Proposed Present Percentage KHH E-82 E-82 Increase E-82 E-82 Increase 0 $ 15.00 $ 15.00 0.0X $ 15.00 $ 15.00 0. O%%d 100 18. 81 18.'13 3.8 20.84 19,. 98 4.3 200 22.62 21.25 6.4 26.68 24.95 6.9 400 30. 24 27.51 9.9 38.36 34.91 9.9 600 37.86 33. 76 12.1 50.04 44. 86 11.5 800 45.48 40.02 13. 6 61.72 54.82 12. 6 o 1,000 53.10 46. 27 14. 8 73.40 64.77 13. 3 1,200 60. 72 52.52 15.6 85.08 74.72 13.9 1,400 68. 34 58. 78 16. 3 96.76 84. 68 14. 3 1,600 75.96 65.03 16. 8 108. 44 94. 63 14.6 1,800 83. 58 71.28 17. 3 120.12 104.58 14.9 2,000 91.20 77. 54 17. 6 131 . 80 114. 54 15.1 2,500 110. 25 93.17 18. 3 161.00 139.42 15.5 3,000 129.30 108. 81 18. 8 190.20 164.31 15.8 3,500 148.35 124.44 19.2 219.40 189.19 16.0 4,000 167.40 140.08 19. 5 248.60 214.08 16.1

T E25 COMPARISON OF PROPOSED E-82 WITH PRESENT E-82 AND WITH PROPOSED f-23 FOR TEN CUSTOMER PATTERNS Customer Annual Proposed Present Percentage Proposed Percentage Pattern KWH .E-82 E-82 Increase E-23 E E-23 1 3,964 $ 370. 89 340.28 9.0X $ 325. 78 13.@

2 4,963 418.62 380.33 10.1 390.45 7.2 3 9,130 612.45 542.59 12.9 615. 29 (0.5) 4 11,170 748. 18 659.24 13. 5 755.61 (1.0) 5 12,878 837. 27 734.53 14.0 848.66 (1.3) 6 14,880 941. 75 822.83 14. 5 956.92 (1.6) 7 16,642 965.85 838.71 15. 2 963.26 0.3 8 18,588 1,048.86 907.64 15. 6 1,038.43 1.0 9 19,522 1.110.95- 961.00 15.6 1,100.61 0.9 10 20,497 1,191. 20 1.030.17 15.6 1,193.55 (0.2)

TABLE 26 COMPARISON OF PROPOSED E-82 WITH PROPOSED E-23 FOR VARIOUS USAGE LEVELS Hinter Surfer Proposed Proposed E-82 Proposed Proposed E-82 Kl<H E-82 E-23 ~Savin s E-82 f-23 ~Savin s 0 $ 15.00 $ 5.00 $ 15.00 $ 5.00 100 18. 81 11.64 20.84 11.77 200 22. 62 18.28 26.68 18.54 400 30. 24 31.56 $ 1. 32 38.36 32.08 600 37. 86 40.42 2.56 50.04 45.62 800 45. 48 49.28 3. 80 61. 72 59. 16 1,000 53.10 55.76 2.66 73. 40 71. 08 1,200 60.72 62.24 1.52 85.08 83.00 1,400 68. 34 68.72 0.38 96.76 94.92 1,600 75.96 75.20 108.44 106. 84 1,800 83. 58 81. 68 120.12 118. 76 2,000 91. 20 88. 16 131. 80 130.68 2,500 110. 25 104. 36 161.00 160.48 3,000 129.30 120.56 190. 20 190.28 $ 0.08 3,500 148.35 136.76 219.40 220.08 0.68 4,000 167.40 152.96 248.60 249.88 l. 28

E"35 COMMERCIAL AND SMALL INDUSTRIAL RATE (GENERAL SERVICE There are approximately 22,000 commercial and small industrial customers on the E-35 standard electric rate schedule. These customers purchase approximately 22 percent of the Salt River Project's energy generation and contribute about 26 percent of the sales revenue. In fiscal year 1981-1982, the average E-35 customer will consume an estimated 124,000 kwh.

The E-35 rate is a general service rate schedule covering a spectrum of customers ranging from small shops, banks and office buildings to large department stores and industries.

Based partially on the class superior rate of return 1 of 8.8 percent vs. the overall rate of return of 6.4 percent and its superior recovery of marginal costs of 133 percent vs. an overall recovery of 116 percent, the E-35 standard electric rate schedule is proposed to increase 11.9 percent, 1.8 percent less than the overall proposed rate increase of 13.7 percent.

The Salt River Project has a history of seasonal rates extending back to 1962. The purpose of these rates is clear--to send a price signal to customers which reflects the cost of providing service. The 1980 TDMC study 2

indicates, that marginal energy costs are 70'percent higher in the summer than I'n the winter. The present E-35 winter to summer rate differentia'1 is 1979 TDHCA.

2 Although load data is in the process of being refined preliminary indications are that approximately 60 percent, of commercial small industrial and energy use occurs in the on-peak rating periods.

93

proposed summer rates being increased 13.0 percent and proposed winter rates being increased 10.8 percent. The summer to winter rate differential with the proposed rates is approximately 20 percent.

The proposed increase is distributed within the class by continuing a trend away from declining block rates. Although the rate structure remains the same, the lower cost end blocks of both demand and energy are proposed to be increased by a larger percentage than the proposed overall class increase of 11.9 percent.

The effects of this transition on higher-use customers is ameliorated by limiting the maximum single customer increase to 16 percent.

En summary:

1) The rates for the summer and winter end energy blocks are p roposed to be increased by 21.9 percent and 18.8 percent, respectively. C

2) The end demand blocks which initial blocks presently decline steeply from the are proposed to increase 22.0 percent and 17.6 t

percent in the summer and winter, respectively. i

3) The initial demand blocks are proposed to increase minimally 7.0 percent and 4.4 percent in the summer and winter, respectively.

4) The third energy block, the "stretcher," is proposed to receive a lower increase--7.1 percent and 4.9 percent in the summer and winter, respectively.

5) The customer charge is proposed to increase from $ 2.75 to $ 5.00 to bring it in line with the results of the historical and marginal cost studies.

94

Table 27A shows the marginal and historical cost recoveries for typical customers below 300 kw. Table 27B shows the marginal and historical cost recoveries for typical customers above 300 kw.

Tables 28 and 29 compare the present and proposed E-3S rates for summer and winter.

Tables 30 and 31 compare typical bills under summer and winter rates. The tables show that, in general, higher-use customers and high load factor customers are proposed to receive a larger than average rate increase.

Table 32 compares annual bills for the proposed rate with present rates. The bills shown are for typical customers with load less than 300 kw.

Table 33 compares annual bills under the proposed rate for typical customers above 300 kw of load. The comparisons depicted are for the present and proposed E-35 rates.

TABLE 27A E-35 TYPICAL COMMERCIAL CUSTOMERS ANNUAL COST COMPARISONS DEMAND LESS THAN 300 KW Peak Average Historical Marginal Average Period Annual Current Marginal (Average) Cost Cost KW Demand KWH Revenue Cost Cost ~Recover ~Recover 9.2 14,168 $ 920 $ 659 $ 832 139.61K 110. 59K 22.8 31,545 2,147 1,301 1,866 165.04 115.08 43.2 38,820 3,127 1,834 3,239 170.56 96.54 28.0 89,836 5,238 3,116 3,132 168.09 167.24 22.4 53,762 3,501 2,010 2,261 174.19 154. 80

31. 2 92,995 5,358 3,201 3.322 167. 39 161.29

38. 2 100,645 6,198 3,576 3,944 173.34 157.18 44.0 180,860 9,522 5,832 5,622 163.29 169.38 153. 0 215,715 15,361 7,902 11,875 194. 38 129.36 93.0 323,230 16,618 10,561 10,643 157. 35 156.14 283. 0 506,547 31,105 18,411 24.797 168.95 125.44 221. 2 819,060 40,088 26,482 26,321 151. 38 152. 31

TABLE 27B E-35 TYPICAL COMMERCIAL CUSTOMERS ANNUAL COST COMPARISONS DEMAND GREATER THAN 300 KW Peak Average SRP Historical Marginal Average Period Annual Current Marginal (Average) Cost Cost KW Demand Demand Revenue Cost Cost ~Recover ~Recover 337.8 875,820 $ 44,253 $ 26,987 $ 34,332 164% 129K 412.0 2,473,027- 87,083 71,896 63,544 121 137 582.4 3,057,560 109,169 93,822 83,989 116 130 605.7 2,696,697 101,240 80,572 79,118 126 128 642.3 2,185,810 90,642 65,524 73.237 138 124 708.0 2,956,440 112,005 88,702 89,446 126 125 781.0 3,914,553 137,785 113,854 108,290 121 127 1086.0 5,980,880 200,825 176,416 159,550 114 126

TABLE 28 GENERAL SERVICE RATE (E-35)

SUMMER (NAY 15 OCTOBER 14)

PRESENT PROPOSED SERVICE CHARGE SERVICE CHARGE

$ 2,85/KW FIRST 220 KW OVER 10 KW $ 3.05/KW FIRST 220 KW OVER 10 KW 1,64/KW ALL ADDITIONAL KW $ 2.00/KW ALL ADDITIONAL KW ENERGY CHARGE ENERGY CHARGE

$ 0,077569/KWH FIRST 400 KWH $ 0.0877/KWH FIRST 400 KWH

0. 063169/Kl'JH NEXT 3,600 KWH 0.0677/KWH NEXT 3,600 KWH 0.058469/KWH f'lEXT 100 KWH/KW 0,0626/KWH NEXT 100 KWH/KW 0,038769/KWH NEXT 50,000 KWH 0,0471/KWH NEXT 50,000 KWH 0.027969/KWH ALL ADDITIONAL KWH 0, 0341/KWH ALL ADDITIONAL KWH CUSTOMER CHARGE, CUSTOMER CHARGE

$ 2,75/MONTH $ 5.00/MONTH MI N I NUM MINIVUV

$ 7.75/MONTH $ 8.50/MONTH

0 i>>

GENERAL SERVICE RATE (E-35)

WINTER (OCTOBER 15 NAY 14)

PRESENT PROPOSED SERVICE CHARGE SERVICE CHARGE

$ 2.49/KW FIRST 220 KN OVER 10 Kl< $ 2,60/0 FIRST 220 KW OVER 10 KM

. 85/Kl< ALL ADDITIONI KM 1.00/KM ALL ADDITIONAL KH ENERGY CHARGE ENERGY CHARGE

$ 0,067669/KNH FIRST 400 KWH $ 0,0744/KNH FIRST 400 KWH

0. 052169/KWH NEXT 3,600 KNH 0.0558/eH NEXT 3,600 Kl"lH

0. 051269/KNH NEXT 100 KNH/KH 0.0538/KWH NEXT 100 KMH/KW 0.032869/KllH NEXT 50,000 K'HAH 0.0385/KVH NEXT 50,000 KMH 0.025169/KWH ALL ADDITIONAL KNH 0,0299/KMH . ALL ADDITIONAL CUSTOMER CHARGE CUSTOMER CHARGE

$ 2.75/NONTH $ 5.00/MONTH NI N IMUM NI NI MUM

$ 7.75/NONTH $ 8.50/NONTH

TABLE 30 E-35 CONPARI SONS AT DIFFERENT LOAD FACTORS SUNNER (NAY 15 - OCTOBER 14) 70 LOAD SRP SRP FACTOR I' PRESE>lT PROPOSED INCREASE 20 10 $ 100,74 $ 111,84 . 11,02 20 50 568,13 612,38 7,79 20 100 1,125,64 1,212,56 7.72 20 200 2,173,66 2,360,22 8,58 20 400 4,064,02 4,477.04 10,16 20 600 5,918,07 6,562,36 10,89 20 1000 9,626,18 10,733,00 11,50 20 2000 18,486,Q6 20,665,60 11,79 40 10 192,96 210,68 9,18 40 50 884,64 982,56 11,07 40 100 1,691,66 1,900,22 12.33 40 200 3,305,72 3,735,54 13,00 40 400 6,081,89 6,931,28 13,97 40 600 8,653,28 9,892,72 14,32 40 1000 13,796,06 15,815,60 14,64 40 2000 26,653,01 30,622,80 14,89 60 10 283,40 307,59 8,53 60 50 1,167,65 1,326.39 13,59 60 100 2,257,69 2,587,88 14,63 60 200 4,290,89 4,934,06 14,99 60 400 7,715,23 8,922,72 15,65 60 600 11,103,36 12,879,88 16,00 60 1000 17,879,53 20,794,20 16,30 60 2000 34,819,96 40,580,00 16,54 100

TABLE,.31 E-35 COMPARISONS AT DIFFERENT LOAD FACTORS k! INTER (OCTOBER 15 - MAY 14)

LOAD SRP SRP 70 FACTOR IQ< . PRESENT PROPOSED INCREASE 2.O 10 $ 85,12 $ 93,91 10,33 20 50 486,41 517.18 6,33 i 20 20 100 200 974,14 1,887,02 1,030,74 2,005,84 5,81 6,30 i 20 20 400 600 1000 3,434,00 4,931,77 7,927,32 3,684.04 5,314,24 8,574,64 7,28 7,76 8,17 l~ 2O 4o 2000 10 15,123,60 161.28 16,398,84 175,38 8*.43 8,74 g 757,64 824,24 8,79 40 50 i 40 40 100 200 1,454,02 2,846,80 1,592,84 3,130,04 9,55 9,95 10,78 40 400 5,177,99 5,736,36 40 600 7,339,86 8,160,52 11,18 40 1000 11,663,60 U,008,84 11,53 40 2000 22,472,95 25,129,64 11,82 60 10 237,11 256,08 8,00 60 50 997,58 1,105.29 10,80 60 100 1,933,91 2,154,94 11,43 60 200 3,701.85 4,137,28 11,76 60 400 6,647,86 7,482.52 12,56 60 600 9,544,66 10,779.76 12.94 g 60 60 1000 2000 15,338,27 29,822,29 17,374,24 33,860,44

13. 27 13.54 101

TABLE 32 TYPICAL COMMERCIAL CUSTOMERS ANNUAL BILL COMPARISON DEMAND LESS THAN 300 KM PEAK X CHANGE PERIOD ANNUAL PROPOSED/

U58 ELK PR0EHZ 9.2 14,168 $ 920 $ 1,029 11.4 22,8 31,545 2,147 2,336 43.2 38,820 3.127 '3,378 8.0 28,0 89,836 5,238 5,729 9.4 22,4 53,762 3,501 3,785 8.1 31.2 92,995 5,358 5,851 9.2 38,2 100,645 6, 198 6,722 8.5 44.0 180,860 9,522 10,565 11,0 153.0 215,715 15,361 16,394 6,7 93.0 323,230 l6,618 18,571 11.8 283.0 506,547 31,105 34,009 9,3 221.2 819,060 40,088 45,138 12,6

TABLE 33 TYPICAL COMMERCIAL CUSTOMERS ANNUAL BILL COMPARISON DEMAND GREATER THAN 300 KW PEAK X CHANGE PERIOD ANNUAL PROPOSED/

MSL EE23I 337. 8 875,820 $ 48,001 $ 53,010 10.4 412. 0 2,473,027 95,511 109,398 14.5 582.4 3,057,560 119,715 137,105 14.5 605.7 2,696,697 110,767 125,989 13.7 642.3 2,185,810 98,839 111,247 12,6 708. 0 2,956,440 122,482 139;094 HQGP II'81.

0 3,914,553 150,998 172,627 14,3 1,086,0 5,980,880 220,463 253,421 14.9

104 E-36 TOTAL ELECTRIC SCHOOL OR CHURCH SERVICE This rate has been frozen since 1975 with no further applications for service bein'g accepted. It is identical to the E-35 general service rate except that it has no service charge in the winter season (no winter demand charge). Tables 34A and 34B show the proposed changes.

The E-36 rate was initiated in the mid-1960's as an incentive for schools and churches to install electric heat-pump heating and to enjoy other benefits of total electric space and water heating.

When the E-36 rate was offered to schools and churches, Salt River Project representatives discussed total-electric benefits with customers, including substantial first cost savings because a heat pump is only slightly more expensive than refrigeration alone, longer equipment life, lower labor and maintenance expense, individual room controls, less interior redecorating expense and safer installation. These advantages of total-electric coupled with a competitive winter rate for electricity resulted in approximately 250 customers receiving service under the E-36 rate by 1975 when it was frozen.

About one-half of the customers are schools and one-half are churches.

Since incentives for electric consumption no longer are considered appropriate and these customers have realized significant saving0 during a period of rising energy costs, it is proposed that this rate be eliminated by October 15, 1982. Existing customers would transfer to the E-35 general service rate or, at their option, to the E-32, time-of-day rate. The E-32 rate has no demand charges off-peak and weekends are included in its winter off-peak period. Thus, many E-36 customers transferring to E-32 would see only a minor change in bills.

105

Table 35 illustrates the effect of a transition from E-36 to E-35 or E-32 rate schedules at several different levels of load. The usage levels shown range from 10 to 200 kw and 10 to 60 percent load factor.-

Transition to E Because E-36 and E-35 are identical rate schedules in the summer period, this change will not affect charges during the t five summer months. However, E-36 does not charge for winter demand.

winter comparison shows that these changes have the largest impact on low load The l

factor customers. Overall winter bills are shown to increase from breakeven to 61 "percent. Again, E-36 and E-35 rates are identical for usage levels below 10 kw because the E-35 rates do not have a charge for the first 10 kw.

On an annual basis, the identical summer charges reduce the impact of the higher winter charges. Annual bills increase as much as 26 percent for low load factor customers but less than 12 percent for the high load factors.

Transition to E The transition to the E-32 time-of-day rate would be advantageous to moderate load factor customers at typical load patterns or to low load factor customers who establish their peak demand in the off-peak period. For example, a church might peak on the weekend in the winter. The table shows that annual bills for typical E-32 load patterns would vary from a 69 percent increase to a 6 percent decrease. It must be emphasized that these comparisons are at typical class on and off peak usages.

E-36 usage patterns are likely to be more predominantly off-peak.

106

TA TOTAL ELECTRIC SCHOOL OR CHURCH SERVICE (E-36)

A FROZEN RATE (ELItlIilATIONPROPOSED)"

SUI'1ljER (I'1AY 15 OGToBER 14)

PRESENT RATE PROPOSED RATE SERVICE CHARGE SERVICE CHARGE

$ 2 85/KItJ FIRST 200 KH OVER 10 KM $ 3. 05/KtJ FIRST 200 Ot OYER 10 KH 1.64/KN ALL ADDITIONAl Ol 2.00/KH =-ALL ADDITIONAL KN ENERGY CHARGE ENERGY CHARGE

$ 0,077569/KNH FIRST 400 K'AH $ 0,0877/KNH FIRST 400 KHH 0,063169/KMH NEXT 3,600 Kl'JH 0.0677/KNH <<FXT 3,600 K~JH 0,058469/KWll tlEXT 100 KHH/KN 0.0626/KNH NEXT 100 KNH/KW 0,038769/KHH NEXT 50,000 Kh'JH 0.0471/KLJH flEXT 50,000 KHH 0,027969/IOH ALL ADDITIONAL KNH 0. 0341/KHH ALL ADDITIONAL KWH CUSTOMER CHARGE Cu

$ 2.75/ltONTH $ 5.00/I'10NTH MINIMUM MINIMUM

$ 7.75/NONTH $ 8.50/NORTH PROPOSE ELIMINATION OF THIS RATE SCHEDULE BY OCTOBER 1985m

TABLE 34B TOTAL ELECTRIC SCHOOL OR CHURCH SERVICE (E-36)

A FROZEN RATE (ELIHINATION PROPOSED)"

MINTER (OCTOBER 15 NAY 14)

PRESENT RATE PROPOSED RATE SERVICE CHARGE SERVICE CHARGE NONE NONE ENERGY CHARGE ENERGY CHARGE

$ 0,067669/KMH FIRST 400 KWH $ 0,0744/KMH FIRST 400 KWH 0.052169/KMH NEXT 3,600 KMH 0.0558/KMH NEXT 3,600 KMH 0, 051269/KWH NEXT 100 KWH/KW 0,0538/KMH NEXT 100 KMH/KM 0,032869/KWH NEXT 50,000 KWH 0.0385/KMH NEXT 50,000 KMH 0,025169/KMH ALL ADDITIONAL KMH 0,0299/KMH ALL ADDITIONAL CUSTOMER CHARGE CUSTOMER CHARGE

$ 2,75/NONTH $ 5.00/NONTH NINIVUm NININUM

$ 7.75/NONTH $ 8.50/NONTH PROPOSE ELIMINATION OF THIS RATE SCHEDULE BY OCTOBER 1985.

TABLE 35 EFFECT ON E-36 CUSTOMERS OF TRANSFERRING TO THE E-35 RATE SCHEDULE OR THE E-32 RATE SCHEDULE Winter Bill Com arison Sumner Bill Com arison Annual Bill Co arison E-36 5/3 E-36 E-35 E-32/- E-35 E-32 E-36 E-35 E-32 Load Monthly Monthly E-35 Monthly E-32 Monthly Monthly E-32 Annual Annual E-35 Annual E-32 Factor KW Bill Bill E-36 Bill E-36 Bil'I Bill E-34 Bil) Bill E-36 Bill E<<36 10 10 $ 53 $ 53 OX $ 89 68'L $ 62 $ 105 695 $ 681 $ 681 OX $ ),148 69K 10 20 94 120 28 147 56 142 180 27 1,368 1,550 13 1.929 41 10 50 216 320 48 323 50 382 406 6 3,422 4,150 21 4,291 25 10 100 413 647 57 616 49 765 781 2 6,716 8,354 24 8,217 22 10 200 806 1.300 61 1.202 49 1,527 1)532 13,277 ,16,735 26 16.074 21 30 10 135 135 0 150 ll 161 179 ll 1,750 1,750 l5 1,945 11 30 20 256 282 10 269 5 338 329 ( 3,482 3,664 5 3 528 1 30 50 580 684 18 629 8 811 8,115 8,843 9 8,288 2 30 100 1.078 1,312 22 1,227 14 1,556 1,523 15,326 16,964 ll 16,204 6 o 30 200 2,074 2,568 24 2,425 17 3,048 3,016 ( 29,758 33,216 12 32,055 8 60 10 256 256 0 241 (6) 308 3,332 3 332 0 3,142 (6) 60 20 450 476 6 453 1 570 551 3 6,000 6,182 3 5,926 (1) 60 50 1,001 1.105 10 1,087 9 1,326 1,333 1 13,637 14,365 7 14.274 5 60 100 l)921 2)155 12 2,145 12 2,588 2,636 2 26,387 28,025 6 28 195 7 60 200 3.643 4.137 14 4,259 17 4,934 5,243 6 50,171 53,629 7 56)028 7

/1 All bills based on proposed standard electric rate schedules

/2 Customers were billed. using the typical E-35 load pattern.

/3 E-36 and E-35 rate schedules are identical in the summer.

3

110 E-32 GENERAL SERVICE OPTIONAL TINE-OF-DAY RATE The E-32 time-of-day rate is an optional rate presently offered on a voluntary basis to all E-35 commercial and small industrial and customers with peak demands of 300 kw or greater and to E-36 customers. In the two years since the rate inception, only one customer has taken service under the rate.

The proposed rate has been substantially redesigned to make it applicable to both E-35 and E-36 classes. The changes more closely reflect the marginal cost of providing service, making the rate more attractive to customers who can shift load into the off-peak period, and also track the revenue requirements of the commercial and small industrial class. Since the proposed rate redesign is expected to appeal to a broad spectrum of customers, it is proposed that a total of 3,000 customers be allowed on time-of-day rates, allocated between industrial and commercial customer classes as participation dictates. The present limit is 1,000.

Although it is proposed that the rate be made available to all E-35 and E-36 customers, it must be recognized that the design of the rate necessarily narrows the range of customers who will find it economical. The proposed customer charge of $ 30 and proposed demand charges for the first 10 kw of demand will render the rate uneconomical for customers below 15 kw unless their peak demand occurs in the off-peak period or their enexgy usage is predominantly off-peak. Likewise, the relatively high proposed on-peak energy charge may render the rate uneconomical for customers above 300 kw of demand who have generally high load factors.

The potential savings under the proposed rate are illustrated by the existing E-32 customer. Although this customer has a peak demand in excess of 111

percent belov the corresponding E-35 bill because the demand occurs off-peak.

The proposed changes in the rate are as follows:

/

1) The customer charge i's proposed to be increased from $ 25.00 to

$ 30.00.

2) Off-peak demand charges are proposed to be eliminated.

3) On-peak demand charges are proposed to be reduced from $ 4.10/kw to'$3.80/kv in the on-peak summer period and from $ 3.41/kw to

$ 2.80/kw in the on-peak winter period.

4) On-peak energy charges are proposed to increase 43 percent, from

$ 0.04669/kwh to $ .0667/kwh in the summer peak period, and 37 percent, from $ .038669 to $ .0528/kwh in the winter peak period.

5) Off-peak energy charges are proposed to be at $ .0280/kwh, The resulting in a 29 percent increase for the percent increase for the winter.

following tables delineate the proposed changes.

summer and a Table 36 shows el the present and proposed criteria and restrictions. Tables 37 and 38 compare the proposed summer and winter rates with the existing rates.

The impact of the time-of-day rate on different customer load patterns is illustrated by Tables 39 and 40. These tables show typical customers with 30 percent of their usage in the on-peak period receiving higher bills ranging from 1 percent to 17 percent in the summer period. These proposed increases are slightly offset in the winter where bills decrease up to 6 percent for some customers with. usage 30 percent off-peak.

112

T 3g

-32 OPTIONAL CONNERCIAL SERVICE T I f1E-Of.-DAY RATE VOLUNTARY VOLUNTARY LINITED TO E-36 CUSTOf1ERS AND OFFERED TO ALL E-35 AND E-36 CUSTOf'lERS CUSTONERS HITH 300 KH OR GREATER DENAND 475.00 ACCOUNT CHARGE NO ACCOUNT CHARGE NAY CANCEL AND RETURN TO STANDARD RATE E-35 AT ANY'INE WITH NORMAL NOTICE.

AFTER CANCELLATION A CUSTOMER MAY NOT RETURN TO E-32 FOR AT LEAST ONE YEAR ~

SUMMER ON PEAK HOURS ARE 10 '0 A N e ~ TO 10 '0 P sH DA I LY (tiON SUN)

H I NTER ON PEAK HOURS ARE 7 00 A N ~ ~ TO 10: 00 P ~ Na MONDAY FR I DAY ~

OFF-PEAK HOURS ARE ALL OTHER HOURS, SUMMER SEASON IS NAY 15 OCTOBER 10, HINTER SEASON IS OCTOBER 15 f'".AY 1 f.

TABLE 37 E-52 Col';NERCI AL SERVI CE TINE OF DAY RATE SUN1ER

$ 25/NONTH $ 50/NONH ON-PEAK $ 4,10/KW ALL KW ON-PEAK Q.80/KW ALL KW OFF-PEAK $ 1.10/KW ALL KW OFF-PEAK NO KN CHARGE ON-PEAK $ 0,046669/KWH ON-PEAK $ 0.0667/KWH OFF-PEAK $ 0.021669/KWH OFF"PEAK $ 0.0280/KWH 10:00 A.z. 10:00 P.z.

NONDAY SUNDAY O RS ALL OTHER

$ 75 Ol

I~ ~8 E-32 CO!~NERCIAL SERVICE TINE-OF-DAY RATE HINTER

$ 25/NONTH $ 30/hONTH ON-PEAK OFF-PEAK

$ 3.01/KH ALL KH

$ 0.75/KH ALL KH ON-PEAK OFF-PEAK

$ 2.80/I t'IO 0 ALL CHARGE I

ON-PEAK $ 0,038669/KI ON-PEAK $ 0,0528/KWfl OFF-PEAK $ 0 020069/KWH OFF-PEAK $ 0.0280/KNtI 7:00 A.N. 10:00 P.N.

FlONDAY SUNDAY At L OTHER

Tables 39 and 40 further show that customers who can shift energy usage to 50 percent off-peak receive a bill decrease of up to 10 percent in the summer and 13 percent in the winter.

Table 39

'E"32 General Service 0 tional Time-of-Da Rate Summer Proposed E-32

% Off-Peak Ener Use Proposed E-35 30% 50%

Load Monthly Monthly  % Monthly Factor kw Bill Bill ~Chan e Bill ~Chan e 20 . 15 $ 177 208 17% $ 191 8%

20 25 306 326 7 298 (3) 20 50 612

'22 2 566 (8) 20 75 917 918 834 (9) 20 100 1,213 ',214 1,102 (9) 20 200 2,360 2,398 2,174 (8) 20 300 3,434 3,583 3,246 (5) 30 15 251 268 7 243 (3) 30 25 422 427 1 384 (9) 30 50 811 823 1 739 (9) 30 75 1,184 1,220 3 1,094 (8) 30 100 1,556 19617 4 1,448 (7) 30 200 3,048 3,203 5 2,866 (6) 30 300 4,466 4,790 7 4,284 (4) 40 15 323 328 2 295 (9) 40 25 524 527 1 471 (10) 40 50 983 1,024 4 912 (7) 40 75 1,441 1,522 6 1,353 (6) 40 100 1,900 2,019 6 1,794 (6) 40 200 3',736 4,008 7 3,558 (5) 40 300 5,451 4,997 10 5,322 (2) 116

Table 40 E"32 General Service 0 tional Time-of-Da Rate Minter Proposed E-32

% Off-Peak Ener Use Proposed E-35 30% 50%

Load Monthly Monthly  % Monthly Factor kv Bill Bill ~Chan e Bill ~Chan e 20 15 $ 148 171 16% $ 160 9%

20 25 255 266 247 (3) 20 50 517 501 (3) 465 (10) 20 75 799 737 (5) 682 (12) 20 100 1,031 973 (6) 900 (13) 20 200 2,006 1,916 (4) 1,770 (12) 20 300 2,869 27858 2,640 (8) 30 15 209 221 6 205 (2) 30 25 354 349 (1) 321 (9) 30 50 684 667 (2) 612 (11) 30 75 998 986 (1) 904 (9) 30 100 1,312 1,304 (1) 1,195 (9) 30 200 2,568 2,579 27960 (8) 30 300 3,712 3,853 4 3,524 (5) 40 15 269 271 1 249 (7) 40 25 440 431 (2) 395 (10) 40 50 824 833 1 760 (8) 40 75 1,209 1,234 2 17125 (7) 40 100 1,593 1,636 3 17490 (6) 40 200 3,130 3,241 4 2,949 (6) 40 300 4,524 4,847 7 4,409 (3)

~

~

gl

~

~

118

E-39 LARGE INDUSTRIAL CUSTOMERS WITH DEMANDS ABOVE 5 000 KILOVATTS The E-39 large industrial rate schedule was implemented in 1976 as an alternative to the E"35 general service rate schedule. For fiscal year 1981-1982 it is projected to include customers receiving service at 19 separate delivery points.

Changes to the large industrial rate are proposed to satisfy four objectives. The first objective, is to increase total fiscal year 1981-1982 revenues 16 percent for the class. This is met as the increased revenues for the period are projected at $ 8,274,932 or 16 percent of the revenues before the proposed increase.

A second objective is to remove the second off-peak rate block in summer and winter. Removing these blocks directly increases the energy costs for those customers above 4,000,000 kwh off-peak usage. A total of eight of the 19 customer bills increase directly as a result of this proposed change, ranging from a high of 2.55 percent for the highest energy usage down to less than .1 percent for usage just over the 4,000,000 kwh block.

A third objective is to spread the increase so that no customer receives a disproportionate amount of the increase. The proposed averages for fiscal year 1981-1982 range from a low of 14.14 percent to 17.78 percent with the larger customers proposed to receive the greater percentage increase. The majority of customers are proposed to receive a 14.5 to 16.5 percent increase.

Greater emphasis on increasing summer rates as a result of both marginal and average cost studies is the fourth objective. Figure 4 represents the percentage sh'ift in summer/winter revenues resulting from the proposed rate adjustment. The overall effect is that summer revenues are 119

proposed to increase approximately 2 percent from the current summer/winter relationship.

FIGURE 4 Summer/Minter I

Revenue Shift Total Revenues Winter 56% Winter 54%

Summer 44% Summer 46%

Current Proposed Table 41 shows the proposed summer and winter revenues. Chart 1 depicts the percentage increases and new revenue dollars for summer and winter applied to the current revenue base. The effect of the rate changes increase summer revenue approximately 20.8 percent while winter revenue increases by only 12.2 percent.

Table 41 E-39 Summer Winter Com arisons Summer Winter Total Current $ 22,670,000 $ 29s007s000 $ 51,677,000

(% of Total) (44%) (56%) (100%)

Proposed 27,392,000 32,560,000 59.952,000

(% of Total) (46%) (54%) (100%)

Increase 4,723,000 3,552,000 8,275,000

(%) (20.8%) (12.2%) (16.0%)

120

CHART 1 Summer/Minter Percentage Increases 35 12.2 30 j.

25 20.8 REVENUES

$ MILLIONS C)

Ch 15 C4 C4 A A 10 O O l4 O O C4 C4 SUMMER WINTER Table 42 is a comparison of present and proposed winter and summer rates. Table 43 shows typical usages for five customers. The proposed increases for summer range from 20.1 percent to 22.1 percent. Proposed winter increases range from 10.7 percent to 14.2 percent. The annual increase proposed H

for the five typical customers ranges from 14.8 percent to 17.7 percent.

121

TABLE 42 E-39 LARGE INDUSTRIAL SERVICE RATE BIB.IER ON PEAK SERVICE: $2 39/Kw ALL Kw $ 2, 64/KW ALt Kw ON PEAK ENERGY.'0 026669/KWH ALL KWH $ 0, 0294/KWH AL KWH OFF PEAK SERVICE: $1 09/Kw ALL Kw, $ 1,21/KW ALL KW OFF PEAK ENERGY: FIRST 4>000,000 KWH $ 0, 0223/KWH ALL KWH

$ 0,020069/KwH ADDITIONAL KWH

$ 0, 017669/KwH ON PEAK SERVICE: $ 3,00/Kw ALL KW $ 3,46/Kw ALL Kw ON PEAK ENERGY: $ 0,028869/KWH ALL KWH $0 0354/KwH ALL KwH g

OFF PEAK SERVICE: $1 16/Kw ALL Kw $ 1,34/KW ALL Kw OFF PEAK ENERGY: FIRST 4,000,000 KWH $ 0,0248/KWH At L KwH

$ 0,020669/KwH ADDITIONAL KWH

$ 0, 019069/KwH m

122

TABLE 43 E-39 LARGE INDUSTRIAL SERVICE RATE CONPARISON FOR TYPICAL USAGES PRESENT PROPOSED PERCENT M ( XJ3MGZS WC':

5,000 3,000 8 95,107 114,300 20,2 11,000 6,000 194,374 233,400 20.1 20,500 11,500 367,324 444,550 21,0 30,000 16,800 533,879 649,680 21,7 37,500 22,000 689,718 842,200 22,1 m HONTE QNTH 5,000 3,000 86,446 95,658 10,7 11,000 6,000 176,371 195,167 10,7 20,500 11,500 330,336 371,824 12,6 30,000 16,800 478,335 543,387 13,6 37,500 22,000 617,205 704,703 14,2 5,000 36,000 1,080,655 1,241,106 14,8 11,000 72,000 2,206,470 2,533,169 14,8 20,500 138,000 4,148,969 4,825,518 16,3 30,000 201,600 6,017,740 7,052,109 17,2 37,500 264,000 7,769,026 9,143,921 17,7 123

124 E-44 WIND MACHINE SERVICE Wind machines are used for frost control in citrus orchards when the outside temperatures drop to near or below the freezing level.

Since wind machines are used only for a short period during the winter there is very little revenue derived from the energy charge. To compensate Salt River Project for the cost of facilities that must be installed to serve this load, an annual service charge, based on horsepower, is used.

Pro osed Chan es in the Rate - Table 44 The wind machine class is proposed to be allocated an overall increase of 13.7 percent.

Proposed changes in the rate were confined to the horsepower charge.

The energy charge was not proposed to increase because it already approximates the proper level considering that the energy is used exclusively in the winter when energy costs are lower than in other periods of the year.

Calculation of Revenues from Pro'sed Rate Increase - Table 45 Since the energy charge is not proposed to change, all the proposed rate increase for- this class must come from the horsepower charge.

Smaller- wind machines are proposed to be given a somewhat greater increase than the larger wind machines. The smaller wind machines are paying proportionately less of the cost for this class than larger wind machines.<<

This is because it costs nearly as much to install the facilities for a small wind machine as it does for the larger wind machine, while the annual revenue from the small machine service charge, is much less than the revenue from larger wind machine.

<<1979 Study-Rates and Corporate Economics Department.

125

TABLE 44 E-44 i'JIND NACHINE SERVICE PRESENT RATES PROPOSED RATES HORSEPOWER OF SERVICE CHARGE HORSEPOWER OF SERVI CE Cl-lARGE CONNECTED LOAD PER H.P, PER YEAR CONNECTED LOAD , PER E E 1 TO 20 H.P, $ 14,75 1 To 20 H.P, $ 18.15 21 TO 45 H,P, 11,96 21 TO 45 H,P. 14.72 46 TO 65 H.P. 9,60 46 TO 65 H,P, 11.77 66 TO 100 H,P, 8,61 66 TO 100 H,P. 10,42 101 H.P, AND OVER 7.87 101 H.P, AND OVER 9,50 ENERGY CHARGE ENERGY CHARGE

$ 0.0462/K'AH $ 0,0462/KHH

TABLE 45 E-44 WIND MACHINE RATE

-. CALCULATION OF REVENUE FROM RATE INCREASE Average Number of Horse- Current Proposed Revenue Mind power Total Charges Current Charges 9 Proposed Percent Horse ower Machines ~in Grou Horse ower ~Per HP YR Revenue ~Per HP Yr Rates Increase 1-20 6 12 '72 $ 14.75 $ 1,062 18.15 $ 1,307 23.1 21 - 45 20 37.5 :7.50 11. 96 8,970 14.72 11,040 23.1 46 65 24 55 1,320 9.60 12,672 11.77 15,536 22.6 66 99 181 75 13,575 8.61 116,881 10.42 141,452 21.0 99 - Over 42 125 5,250 7.87 41,318 9.50 49 875 20.7 Total Revenues from Horsepower Charge $ 180,903 $ 219,210 21.2 Energy Revenues 2,132,887 KWH 98,539 98,539 Total Combined Revenues $ 279,442 $ 317,749 13.7

128 E-47 AGRICULTURAL PUMPING RATE The Salt River Project's agricultural pumping rate i is a flat kw/kwh rate which means that the rate does not change with different levels of usage.

There are approximately 450 customers on the rate. Revenues from the agricultural rate account for less than 2 percent of the total revenues from electrical sales.

Based on TDHCA study costs, the agricultural pumping class is returning less than the average return. To narrow the gap between this class and the other customer classes, an overall increase of 16.0 percent is proposed to be incorporated into the rate.

Chan es in the Rate The basic flat rate form is proposed to be retained, The minimum bill is proposed to increase from $ 7.75 to $ 8.50 to bring the charge more in line with actual costs and to correspond with the minimum bill for the general service rate (E-35).

Summer and Minter Rate Com arisons - Table 47 The summer and winter differential for the agricultural pumping rate schedule has not been as great as that of some of the other rate schedules and not nearly as large as the,TDHCA. and TDMC studies would indicate. To increase the spread between summer and winter rates, more of the rate increase is proposed to be allocated to the summer season.

Rate comparisons between current and proposed rates (Tables 48 and

49) show that the proposed increase in the summer season will generally range between 16.8 and 18.2 percent while the increase in the winter season will vary between 13.2 and 13 ' percent.

129'

Annual Bill Com arison - Table 50 Selecting three representative customers and billing their monthly usages for the year give an indication of the proposed annual increase that customers of this size, would experience. As would be expected, the annual increases are near the overall proposed average increase of 16.0 percent.

130

HLE 47 E-47 AGRICULTURAL PUMPING RATE (1),'ilJE1El<:

PRES 15-0 SERVICE CHARGE $ 2.19/KH $ 2,39/Kl<

ENERGY CHARGE $ 0,035669/KNH $ 0.0425/KHH FQR ALL KNH FoR AL KMH MINIMUM $ 7.75/MONTH $ 8.50/MONTH (2) l'(INTER:

PRESENT (OCT 15-MAY 14) PROPosED (OcT 15-MAY 1 f)

SERVICE CHARGE $ 0,88/KW $ 1,06/KN ENERGY CHARGE $ 0. 031269/KHH $ 0.0353/OH FoR ALt KNH FoR ALL KO MINIMUM $ 7.75/MONTH $ 8,50/MONTH

TABLE 48 E-47 AGRICULTURAL PUNPING SUNNER RATE CONPARISON NAY 15 OCTOBER 1 KW HOURS CURRENT PROPOSED PERCENT DEMAND PER NO"JTH "KO KORE REKlRL QilRiE

.150 200 '0,000 1,398,57 1,633.50 16.8 200 200 40,000 1,864,76 2,178,00 16.8 250 200 50,000 2,330,95 2,722.50 300 200 60,000 2,797,14 3,267.00 150 400 60,000 2,468,64 2,908,50 17.8 200 400 80,000 3,291.,52 3,878;00 7s0

'250 400 100,000 4,114,40. 4,847.50 17s8 a

300 400 120,000 4,937.28 5,817,00- 17 so 150 600 90,000 3,538,71 ',183.50 18.2 200 600 120,000 4,718.28 5,578.00 8s2 250 600 150,000 5,897,85 6,972,50 lo s2 300 .600 180,000 7,077.42 P,367,00 m.m W m m m hga

M

. 0 TABLE 49 E-47

. AGRI CULTURAL PUI'1P ING t'FAINTER RATE CONPARISOH (OCTOBER 15 - NAY 14)

KL't HOURS CURRENT PROPOSED PERCENT DENAND PER NONTH KNH REVENUE REVENUE CHANGE 150 200 30,000 1,070.07 1,218,00 13.8 200 200 40,000 1,426.76 1,G24,00 13a8 250 200 50,000 1,783.45 2,030.00 Us8 300 200 60,000 2,140.14 2,436.00 13 I 8 150 4OO 60,000 2,008.14 2,277.00 13.4 200 400 80,000 2,677.52 3,036.00 134 3,795.00

'3.4 250 400 100,000 3,346.90 300 400-: 120,000 4,016.28 4,554.00 13.4 150 600 90,000 2,946.21 3,336,00 13e2 200 600 120,000 3,928.28 4,FAIL,S.OO 13eL 250 600 150,000 4,910.35 5,5GO,OO 13.2 300 600 180,000 5,892.42 6,672,00 '13s2 f

TABLE 50 E-47 AGRICULTURAL PUMPING ANNUAL BILL COMPARISONS ANNUAL LOAD HIGH X CHANGE FACTOR KW ANNUAL PROPOSED/

CUSTOMER X DEMAND KMH PRESENT PROPOSED PRESENT 47.9 296 1,241,200 $ 47,455.18 $ 55,449,06 16.8 47,8 216 905,970 55,985,54 59,455.78 16,1 22.1 98,640 4,154,58 4,824,89 16,7

E-50 E"51 K-52'"54 E"55 LIGHTING'ERVICE Sales for the street light class for fiscal year 1981-1982 are projected to be 44,002,'000 kwh. Included in this class are public street lighting service (E-50), private street lighting service (E-51), security lighting service (E-52), traffic signal li'ghting service (E-54) and playground lighting service (E-55).

The proposed rate increase for street lights is 16.0 percent. This is above the proposed average increase for all standard electric rate schedules and represents a revenue increase of $ 553,830.

Each type of street light and pole, in the E-50, E-51 and E-52 rate classes, is related to its annual cost to determine the individual percentage recovery (see Table 51). Those with the lowest return tend to receive the largest rate increase and those with the highest return are proposed to receive a lower rate increase.

Table 51 shows various costs for each street light. To estimate marginal energy cost, average annual kwh have been determined. Using the f

"sunrise and sunset hours for the 15th day of each month as the mean for that month, minutes that coincide with on-peak and off-peak periods are calculated.

These are then totaled for each winter and summer period to provide on/off-peak energy and the corresponding marginal cost.

Similarly, the rated wattage of the luminaire multiplied by the marginal demand cost results in the total marginal demand cost/year. The remaining costs are a composite of various factors such as capital recovery, operation, maintenance and taxes.

The current rate per month divided by the current cost per month provides the current cost recovery per month (shown in Table 51) which is used 1.35

as a guide in determining the proposed increase for each street light and pole.

Table 52 compares the current and proposed rates for lamps and luminaries for the E-50 public street lighting class. Tables 53 and 54 provide the same comparisons for the E-51 private street lighting class and the E-52 security lighting class.

Table 56 compares current and proposed rates for traffic signal i

lighting, E-54. It is proposed that the standard electric rate schedule for traffic signal lighting receive the average proposed increase of 13.7 percent.

Table 57 contains current and proposed rate comparisons for playground lighting, E-55. The proposed E-55 rate is based on the proposed E-35 general service rate.

136

Table 51 E 50 HARGINAL COST ANALYSIS (Includes Fuel Ad)ustment in Current Rates)

Early American Style 175W/

7000 HV*

Contemporary Style 175M/

7000 HV Hodern Style 100W/ 150M/ 250M/ 400W/

9500 16000 30000 50000 HPS*>> HPS IIPS IIPS Streaml ined Style 175M/ 250M/ 400M/ 100M/ 150M/ 250M/ 400W/

7000 11000 20000 9500 16000 30000 50000 HV HV HV HPS HPS HPS HPS Suamer On-Peak Kwh/yr 94 94 54 79 139 215 94 132 213 79 139 215 Sumner Off-Peak Kwh/yr 211 211 122 178 312 484 211 297 478 122 178 312 484 Winter On-Peak Kwh/yr 127 127 73 107 187 290 127 178 287 73 107 187 290 Minter Off-Peak Kwh/yr 420 420 243 356 622 967 420 593 954 243 356 622 967 Kwh/Yr 852 852 492 720 1260 1956 852 1200 1932 492 720 1260 '1956 Total Harginal Energy Cost/Yr $ 17.87 17.87 10.21 14.99 26.43 41.14 17.87 25.11 40.52 10.21 14.99 26.43 41.14 Total Harginal Power Cost/Yr 3.05 3.05 1.74 2.55 4.50 7. 01 3. 05 4. 28 6.90 1.74 2.55 4.50 7.01 Total Fixed Costs/Yr 42.93 43.72 112.04 117.79 144.31 152.41 38.37 42.57 55.43 47.69 53.45 69.44 70.89 Total Cost/Yr 63.85 64.64 123.99 135.33 175.24- 200.56 59.29 71.96 102.85 59.64 70.99 100.37 119.04 Total Cost/Ho 5.32 5.39 10.33 11.28 14.60 16.71 4.94 6.00 8.57 4.97 5.92 8.36 9.92 Current Rate/Ho/w Fuel 5.23 5.23 8.59 9.43 12.98 14.73 5.23 6.26 8.19 5.90 6.54 8.65 10.31 Current Cost Recovery/Ho (X)

Proposed Rates $ /Honth 98.31%

6.07 97.0%

6. 07 83.16%

10.13

83. 60K 11.12 88.90K 15.19 88.15Ã 17.25 105.87%

6.07 104.33~

7.20 16.2L'4 95.57<

9.52

>>8.71~

6.70 110.47K 7.49 103.47%

9.98 103.9%

11.90 Percent Increase 16.1% 16.1% 17.9% 17.9% 17.0$ 17.1% 16.1% 15.0$ l3.6Ã 14.5X 15.1L 15.4%

• 175 watts/7000 Lumen Hercury Vapor

• • 100 watts/9500 Lumen High Pressure Sodium

TABLE 52 PUBLIC STREET LIGHTING E-50 RATE/NONTH BASIC CHARGES (LAMPS LUMINAIREi BRACKETS POWER ENERGY)

STYLE STREAMLINED MODERN LAMP SERVICE Lcm. Qxxs. Ixez""

7,000 175 $ 5,23" $ 6,07" 16.1 10,13 17.9 NV',500 10A. HPS 5,90 6,70 13,6 8,59 11,000 250 NV 6,26 7.20 15.0 16,000 150 HPS 6,54 7.49 14.5 9,43 11,12 17,9 20,000 400 NV 8,19 9.52 16,2 5,84 6.84 .17.1 30,000 250 HPS 8.65 9.98 15.4 12,98 15,19 17.0 5.65 6.49 14.9 50,000 400 HPS 10,31 11,90 15.4 14.73 17 '5 17.1 ALSO AVAILABLE IN EARLY AMERICAN OR CONTEMPORARY STYl E AT SAME RATEs NV = NERCURY VAPOR HPS = H IGH PRESSURE SODIUM

PRIVATE STREET LIGHTING E-51 RATE/NONTH BASIC CHARGES (LAMP> LUMINAIRE, BRACKETS POWER, ENERGY)

STYLE STREAMLINED MODERN EARLY AMERICAN Qi~~ g~ Qpz . ~0 Hm 2 4,000 100 NV $ 5.50 $ 6,37 15.8 7,000 175 NV 5.74 6,64 15.7 6,41 7,41" 15,6 9,500 100 HPS 6,97 7.92 U.6 10.77 12,68 17.7 11,000 250 NV 6,75 7,84 16.1 16,000 150 HPS 7.57 8,68 14 ' 11.16 13.22 18.5 20,000 400 NV 8.95 10,33 15,4 30,000 250 HPS 9,22 10,59 14.9 15.63 18.16 16,2 50,000 400 HPS 11.40 13,06 14.6 17.57 20,47 16,5 ALSO AVAILABLE IN CONTEMPORARY STYLE AT SAME RATE>

TABLE 54 SECURITY LIGHTING SERVICE E-52 RATE/MONTH Lam Service Onl Lam Service Luminaire, Bracket Lumens Matte Tyye Current ~Pro osed ~Chan e Current ~Pro osed ~Chan e ~St le 4,000 100 NV $ 2.76 $ 3.18 15.2 $ 6.75 $ 7.54 11.7 Early American 7,000 175 MV 3.40 3.94 15.9 6.25 7.16 14.6 Streamlined 5.61 6.49 15.7 Open Bottom 7.22 8.37 15.9 Early American 7.22 8.37 15.9 Contemporary 9,500 100 HPS 3.76 4.44 18.1 13.47 15.91 18.1 Nodern 20,000 400 NV 5.99 6.96 16.2 9.41 10.94 16.3 Streamlined 10.28 11.83 15.1 Fl oodl i ght 30,000 250 HPS 5.39 6.18 14. 7 10.75 12.31 14.5 Streamlined 50,000 400 HPS 6.66 7.59 14.0 12.82 14.62 14.0 floodlight

TABLE 56 E-54 TRAFFIC SIGNAL LIGHTING SERVICE PRESENT RATE $ ,055669/KNH PROPOSED RATE $ ,0633/KMH PRESENT NININUM $ 1,50 PROPOSED MIN INUP1 $ 2,00 141

TABLE 57 E-55 PLAYGROUND LIGHTING

($ /OH) 10 ~ ~ ~

Smma~ ~Ic~Zgj Lmxaz; FIRsT 400 $ ,0877 13,1 $ ,0744 9,9 NExT 3600 ,0677 ,7,2 ,0558 7,0 ALL ADD IT IONAL ,0626 7,1 ,0538 4,9 A MINIMUM CHARGE OF $ 8<50 IS APPLIED IN ANY MONTH WITH ENERGY USAGEs

~PRE Sv~za. Kmxm FIRST 400 $ ,077569 $ ,067669 NExT 3600 ,063169 ,052169 ALL ADD.ITIONAL ,058469 ,051269 A MINIMUM CHARGE OF $ 7 75 IS APPLIED IN ANY MONTH WITH ENERGY USAGEs 142

C-60 CHILLED WATER SERVICE FROZEN RATE (Not a standard electric rate schedule.)

The C-60 rate schedule is used by stores in regional shopping centers that utilize chilled water for air conditioning. It has been frozen, which means that no new customers will be served on this rate.

Chilled water customers are billed on a square foot basis with adjustments for sales tax, heat gain, fuel, material, supplies and ~ in-lieu taxes.

Chan es in the Chilled Water Rate - Tables 58 and 59 Chilled water customers are allocated a proposed overall increase of 1

16.0 percent. Recent studies show that this class of customers has a below average return. Proposed rates are given in Table 58.

Since the cost of cooling a square foot of space does not vary substantially with the size of the customer, a flatter rate structure can be used. Progress toward a flatter rate structure is furthered by proposing giving a smaller increase for the earlier rate blocks and a larger increase for the latter rate blocks (Table 59).

Com arison of Monthl Bills for Selected Customers Table 60 compares current and proposed monthly rates for selected customers. Rate increases for these customers are proposed to range from a low of 12.9 percent for a customer cooling 450 square feet to 18.6 percent for 40,500 square feet.

1 1979 Rate and Corporate Economics Department Study.

143

Table 58 C-60 Chilled Vater Service Frozen Rate PRESENT

$ 0.042536 Per square foot for the first 500 square feet of cooled area.

$ 0.041236 Per square foot for the next 2,500 square feet of cooled area.

$ 0.039436 Per square foot for all additional square feet of cooled area.

PROPOSED

$ 0.0480 Per square foot for the first 500 square feet of cooled area.

$ 0.0474 Per square foot for the next 2,500 square feet of cooled area.

$ 0.0469 Per square foot for all additional square feet of cooled area.

el L

A el 144

M W W W W W W W W W W M W W W W M 0

TABLE 59 C-60 CHILLED MATER RATE REVENUES BY RATE BLOCK Square. No. of Sq. Ft. Proposed Revenues Feet of Customers Bi 1 led Current Annual Revenue Base From Proposed Percent Billed Area In Block In Block Base Rate From Current Rates Rates Based Rates Increase First 500 67 33,450 $ 0.042536/No. $ 17,073.95 $ 0.0480 $ 19,267.20 12.8 Next 2,500 65 90,652 0.041236 44,857. 51 0.0474 51,562.86 14.9 All Additional 21 74,054. 0.039436 35,044.72 0.0469 41,677.59 18.9 Total 198,156 $ 96,976.18 $ 112,507.65 16.0 Note: The above figures do not include rate adjustments other than fuel.

Table 60 C"60 Comparision of Monthly Bills for Selected Customers Feet Current Rate- Pro osed Rate  % Increase Rate 450 19. 14 21. 60 12.9%

975 40.96 46. 52 13.6 1,950 81.06 92.73 14.4 3,750 153.94 177.68 15.4 8,024 322.48 378.13 17.3 40,500 1,603.21 1,901.25 18.6 4

NOTE: The above figures do not include adjustments other than fuel.

146

RIDERS TO STANDARD ELECTRIC RATE SCHEDULES There are no proposed changes in the following standard electric rate schedule riders.

X-Ray Equipment Service Rider Velding Equipment Service Rider Interruptible Power Service Rider High Voltage Delivery Rider

148 APPENDIX A NOTES TO SECTION A

I i

t l

I I

I I

I

NOTE 1: FISCAL YEAR 1979-1980 THROUGH FISCAL YEAR 1981-1982 DEBT SERVICE COVERAGE RATIO DEBT RATIO AND AVERAGE ANNUAL INTEREST RATE Charts 2, 3, and 4 in Section A show projected figures for fiscal year 1980-1981 and fiscal year 1981-1982. This note explains the development of those projections. The projections, together with two historical years and chart references, are as follows:

Fiscal Year Chart Calendar No. Title Year 1979 1979-1980 1980-1981 1981-1982 2 Debt 'Service Coverage Ratio 1.73 1.70 1.63 1.38 3 Debt Ratio 83.54 84.24 82.74 82.98 4 Average Annual Interest Rate 6.37 6.70 6.91 7. 10 Debt Service Covera e Ratio. The projections for fiscal year 1980-1981 and fiscal year 1981-1982 come from the 1981/82 Preliminary Revenue Requirements, December 1980.

Debt Ratio. The debt ratio is long-term debt in dollars divided by total capitalization in dollars, where total capitalization is the sum of long-term debt in dollars and accumulated net revenues in dollars. Projected debt ratios are calculated by tracing projected flows of principal repayment of long-term debt, new issues of long-term debt, and net revenues. The following table outlines these flows:

Thousands Total long-term debt--fiscal year-end 1979-1980 1

$ 2,019,998 (A)

Less principal repayments--fiscal year 1980-1981 (21,655)

New long-term debt--fiscal year 1980-1981 175 000 Total long-term debt--fiscal year-end 1980-1981 $ 2,173,343 (5)

Accumulated net revenues--fiscal year-end 1979-1980 3773908 (C)

Net revenues--fiscal year 1980-1981 75 571 Accumulated net revenues--fiscal year-end 1980-1981 453,479 (D)

Total capitalization--fiscal year-end 1980-1981 (B)+(D) $ 2,626,822 (E)

Total long-term debt--fiscal year-end 1980-1981- $ 29173,343 Less principal repayments--fiscal year 19)1-1982 (22,792)

New long-term debt--fiscal year 1981-1982 275 000 Total long-term debt--fiscal year-end 1981-1982 $ 2,425,551 (F)

L Accumulated net revenues--fiscal year-end 1980-1981 $ 453,479 Net Revenues--fiscal year 1981-1982 43 923 Accumulated Net Revenues--fiscal year-end 1981-1982 5 497,402 (0)

L Total capitalization--fiscal year-end 1981-19)2 (F)+(G) $ 2,922,953 (H)

Debt Ratio--fiscal year-end 1980-1981 (B) .(E) 82. 74 Debt Ratio--fiscal year-end 1981-1982 (F) .(H) 82.98 1

Statement of Funds Available, Cash Flow Model.

2 1981/82 Preliminary Revenue Requirements, December 1980.

In the absence of a rate adjustment, the debt ratio for fiscal year 1980-1981 is projected to decrease. This improvement in the debt ratio E without a rate adjustment but with the issuance of more long-term debt is contrary to rational expectations. This apparent aberration is the result of the elimination of million in long-term debt incurring additional

$ 80 short-term debt during fiscal year 1980-1981.

by The additional short-term debt r

is in the form of tax-exempt commercial paper issued by the Salt River Project in the fall of 1980. t)thile heavier reliance on short-term financing improves financial statistics for fiscal year 1980-1981, the trend of an increasing debt ratio is projected to Avera e Annual resume in fiscal year Interest Rate. The 1981-1982.

projections for average annual i

interest rates are weighted averages of the interest rates paid on t

outstanding, long-term debt. The weighting process proceeds from fiscal year-end data through subsequent bond issues in that fiscal year. Actual amounts and interest rates for bond issues are used for issues up through 1980 Series B issued in October 1980. Thereafter, projected principal amounts and 150

interest rates are used. The projected average annual interest rates are as follows:

Amount Millions Rate ~Wei hc Fiscal year-end 1979-1980 2,020.0 6.70% 139534 Fiscal year 1980-1981 bond issues 1980 B 100.0 9.35% 935 1980 C 2.2 7.00% 15 1981 A 75.0 9.25% 694 Principal repayments--fiscal year 1980-1981 ~21. 6 6.70% ~145 Fiscal year- end 1980-1981 2 175.6 6. 91% 15 033 Fiscal year 1981-198) bond issues 1981 B 1'00. 0 8.75% 875 1981 C 75.0 8.75% 656 1982 A2 100.0 8,25% 825 Principal repayments--fiscal year 1981-1982 ~22. 8 6.91% ~158 Fiscal year-end 1981-1982 2,427.8 7.10% 17>231 Average Annual Interest Rate Fiscal year 1980"1981 6,91%

Fiscal year 1981-1982 7.10%

2 1981/82 Preliminary Revenue Requirements, December 1980.

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NOTE 2: FINANCIAL CRITERIA AND SCORECARD This note describes financial criteria and how the Salt River Project compares with similar utilities with which it must compete in the market for debt funds. The three utilities chosen for comparison, together with their abbreviations and ratings, are as follows:

Ratin s Standard Utilit Abbreviation and Poor's i~food 's Los Angeles Department of Water and Power LADWP AA Aa Omaha Public Power District OPPD AA Aa South Carolina Public Service Authority SCPSA A+ Al Salt River Project SRP A+ Aa These utilities are of a similar credit nature, and, more specifically, share the following characteristics: all are public utilities; all have a moderate to strong economic base in their service areas (Note 3); and all issue revenue bonds as their primary source of debt financing. Only SCPSA is distinctly different as to form in that it is a joint action agency which primarily wholesales energy and capacity to its participant municipalities.

Bond ratings reflect distinctions concerning the quality of debt instruments. Higher quality instruments tend to attract relatively higher prices from, the investor (and, thus, relatively lower interest rates for the issuer); conversely, relatively lower quality instruments tend to secure lower prices (and, thus, relatively higher interest rates). This is observable in the primary market (original issue) as well as the secondary market (subsequent trades between investors).

However, even within issues of similar ratings, the interest costs faced by the issuers reveal distinctions. Table 1, which follows, presents interest rate differentials in the secondary market, at given points in time, that existed between issues of the utilities chosen for comparison. The 152

issues used in Table 1 are of similar maturity and coupon rate. With one exception, SRP issues carried higher yields than do similar issues of the other utilities.

Table 1 Secondary Bond Market Levels and Yield Differentials Selected Utilities1 Standard 'ield and Differential B Date Until it & Poor's Ratin ~11 16 80 I//11 80 3//780 ~32 80 ~627 80 SRP 7. 59% 7.91% 9. 62/o 8. 30% 8.12%

LADWP AA 7, 21% 7.50% 9.30% 8.00% 7. 88/o vs. SRP -0.38% -0.41% -0.32% -0.30% -0.24%

OPFD AA 7. 54% 7.77% 9.57% 8 52%2 7. 90%

vs. SRP -0.05% -0.14% -0.05% +0.22% "0.22%

SCPSA 7. 50% 7. 85% 9 58%

~ 8,30% 8. 05%

vs. SRP -0,09% >>0.06/o -0.04% 0 a/ -0,07%

1 SOURCE: A graphical analysis prepared by Lehman Brothers Kuhn Loeb Inc.

based on information accumulated by Municipal Securities Evaluation Service, Inc.

2 An obvious aberration, which could well have been caused by any number of factors--a large block of OPPD bonds suddenly being placed on the market, a negative news report pertaining to OPPD, etc.

There are many factors that determine the quality of an issuer of long-term debt. In general, the factors are the same that determine the credit standing of an individual. Specific factors for the electric utility industry are as follows:

1. Debt service coverage ratio

2. Debt ratio

3. Amount of future financing

4. Operating ratio

5. Revenue bonds outstanding

6. Economic vitality of the service area

7. Management's capability

8. Fuel supply and mix

9. Liquidity

10. Regulatory environment 153

Table 2 contains data for the first five criteria for the four utilities to be compared. These five criteria are further specified as follows:

Annual Debt Service Covera e. Operating revenues available for debt service divided by principal and interest requirements for the twelve-month period.

Debt Ratio. The ratio of total long-term debt to total capitalization.

Future Financin . Total of bonds expected to be issued through the year indicated.

0 eratin Ratio. Operating and maintenance expenses l,'excluding depreciation) divided by total operating revenues; both for the twelve-month period indicated.

Revenue Bonds Outstandin . Includes all bonds outstanding through February 1980.

Table 2 Financial Scorecard 1980 Ranking Recap Future Financin s Annual Debt Thru Service Covera e Debt Ratio Millions Year 1st LADWP 2.02 1st LADWP 62 1st OPPD $ 50 1985 2nd OPPD 1.79 2nd OPFD 81 2nd LADWP 575 1984 3rd SCPSA 1.76 3rd SRP 87 3rd SCPSA 1,322 1985 4th SRP 1.70 4th SCFSA 96 4th SRP 1,986 1985 Moody's/Standard Revenue Bonds 0 eratin Ratio and Poor's Outstandin thousands 1979 Ratin 1st OPPD $ 780,475 1st SRP 55 LADWP Aa/AA 2nd SCPSA 844,890 2nd OPPD 62 OPPD Aa/AA 3rd SRP 1,684,235 3rd LADWP 69 SRP Aa/A+

4th LADWP 1,703,119 4th SCPSA 76 SCPSA A1/A+

Rankings on comparative criteria are stated by the initials of the issuer, and ordered from best to worst, top to bottom. The criteria show how Data for these comparisons come from a report issued in April, 1980 by Dean Witter Reynolds, Inc., entitled Munici al Utilit Bond Valuations.

154

bond ratings tend to correlate strongly with these classic measures of financial health. Further, the criteria reveal why Salt River Project instruments are relatively weaker (Table 1) in the secondary market than are those of the other utilities. Although these criteria are by no means the total basis for the ratings, they do correlate closely with the. bond ratings and yield differentials.

155

NOTE 3: ECONOMIC GROWTH AND FINANCING RE UIREMENTS Growth in Arizona has been dramatic over the past decade. The following table compares the percentage change from 1969 to 1979 in population, personal income, and nonagricultural employment in Arizona with that experienced in other leading growth areas and in the United States as a whole.

Percenta e Chan e 1969-1979 Personal Nonagricultural Po ulation Income Em lo ment Alaska 37e2% 267.0% 93.8%

ARIZONA 41. 0 253.8 87.7 California 15. 1 171.6 39.0 Florida 33.4 231.2 63.3 Idaho 28.0 218,5 67 '

Nevada 46,3 250.9 97.9 Texas 21.1 219.9 55.8 Wyoming 36,8 287.6 89. 7 U. 8.8 158. 0 26.1 SOURCE: U. S Department of Commerce, Bureau of Economic Analysis; U. S.

Department of Labor, Bureau of Labor Statistics; U. S. Department of Commerce, Bureau of .the Census. Data collected by Chase Econometric Associates, Inc.

"-Population includes armed forces abroad; employment includes workers 16 years and older.

The Phoenix area, within which the Salt River Project operates, has also exhibited extremely rapid growth. As shown on the table, "Comparative Economic Statistics for Major Metropolitan Areas," growth in the Phoenix area--in terms of population, new housing, and income--has been outstanding in absolute terms and relative to that of other metropolitan areas.

As Maricopa County (which includes the City of Phoenix and its suburbs) has grown, so has the number of electric customers served by the Salt River Project--but even more rapidly, in most cases, as indicated in 156

COHPARATIVE ECOHOHIC STATISTICS FOR NJOR HETROPOLITAH AREAS.

1978 Total Total Pop. Total Hew Housing Total Hon-Agricul tural Standard Hetropol i tan Pop. 1968 1978 W Change -Units Authorized- -Empl oymenM- -Per Capita lncome-Statistical Area Rank ~Po .* ~Po .* 96S-'78 1969 1979 . ~XChan n 1969 1979 ~%Chan e )969, 1979 ~%Chan e Phoenix, A2 30 914 1,293 41.5 19,316 34,568 79.0 30& 608 97.4 3.264 8,170 150.3 Hew York, HY-HJ 1 9,805 9,222 (5.9) 37,178 13,603 (63.4) 4,167 3,718 (10.8) 4,590 S,S52 92.9

. L.A.-Long Beach, CA 6,928 7.OSl 2.2 41,095 36.145 (12.o) 2,900 3,596 24.0 4,190 9,399 124.3 Chicago. IL 3 6,BS2 7,030 2.2 52,058 27,023 (48.1) 3,027 3,219 6.3 4,377 9,493 116.9 Philadelphia, PA-HJ 4 4,737 4,770 0.7 23,439 19,293 (17.7) 1,808 1,927 6.6 3,856 8,162 111.7 San Fran.-Oakland, CA 7 3,072 3,184 3.6 21,143 17,974 (15.0) 1,257 1,518 20.8 4,616 10,492 127.3 Dallas-Ft. Morth, TX 9 2,190 2,720 24.2 25,679 44.040 71.50 938"*1.385 47.7 3,748 8,756 133.6 Houston, TX 11 1,923 2,595 35.0 57,730 55,8S9 (3.2) 739 1,366 84.8 3,4' 9,398 171.8 Atlanta, GA 18 1,549 1,852 )9.5 24,009 23,679 (1.4) 603 931 54.4 3,473 8,238 -137.2 San Diego. CA 20 1,286 1,744 35.6 24,979 18,525 (55.8) 374 634 69.5 3.807 7,g47 108.7 Denver-Boulder, Co 21 1,201 1,505 25.3 15,948'2,199 39.2 462 777 6&.2 3.547 9,OSO 156.O Seattle-Everett, MA 22 '.371 1,468 7.0 189231 22,335 22.5 560 761 35.9 4,269 g,582 124.6 Kansas City, N-KS 28 1.226 1,325 8.0 11.250 7.944 (29.4) 512 638 24.6 3,873 8,524 120.1 SOURCE: U.S. Department of Conmerce, Bureau . . De p artment of Labor,'ureau of Labor Statistics.

of the Census and Bureau of Economic Analys is ; U.S. Data oOOasned from Chase Econometric Associates, lnc.; data base on standard metropolitan statistical areas throug h ou t th e Unitedn e States, Host recent data available.

• In thousands.

• " Data unavailable for 1969. Figure shown is for 1970.

the following table:

Percent Increase Percent Increase - Po ulation Year Electric Customers Marico a Count State of A'rizona 1971 9.4 4.9 5.8 1972 10.8 5.2 5.2 1973 9.7 5.2 5.1 1974 5.8 4.2 4.0 1975 4.2 2.7 2.3 1976 3.6 3.3 2.9 1977 4.3 5.9 4.2 1978 7.1 7.2 7.7 1979 7.6 2.8 3.3 1980 (estimated) 6.1 2.5 3.0 SOURCE: Salt River Project Agricultural Improvement and Power District, Official Statement, 1980 Series B Revenue Bonds, October 17, 1980, p. 6.

Growth in electric customers as of December 31; growth in population as of July 1.

The economic diversity of the Salt River Project service area can be demonstrated by comparing the percentage of total nonagricultural employment comprised by each sector of the economy in Maricopa County, as shown in the following table.

Percentage of Total Nonagricultural Employment Industr Ma 1980 Manufacturing 17.69 Mining .05 Construction 7.69 Transportation & Utilities 4.64 Vholesale & Retail Trade 25.65 Finance, Insurance &, Real Estate 6.95 Services &, Miscellaneous 20.36 Government 16,97 SOURCE: U. S. Department of Labor, Bureau of Labor Statistics. Data obtained from Chase Econometric Associates, Inc , data base.

Although Maricopa County and the state as a whole are growing and diversified areas, they are not insulated from national economic disturbances.

Forecasts for the Phoenix area reflect some negative repercussions from a national recession. According to Chase Econometric Associates, Inc. (October 1980 forecast), a forecasting service, nonagricultural employment and housing 158

I starts in the area for the final quarter of 1980 may fall below their levels in the last quarter of 1979. By the first, quarter of 1981, however, nonagricultural employment is predicted to regain momentum; housing activity is also predicted to improve in the first quarter, although the outlook for later quarters is not as strong.

These cyclical fluctuations are important and require appropriate short-term operational responses; such variations do not, however, alter the long-term trend of growth in the area. Planned construction is directed towards meeting the needs of such long-term growth. Thus, the Sa3.t River Project must finance new facilities throughout their construction and incur substantial amounts of debt on a continual basis during that period, in spite of short-term changes in business activity and whether or not market rates of interest are at unfavorably high levels.

159

NOTE 4: STATISTICS The debt service coverage ratio is subject to variability due to uncontrollable and outside influences on revenues and expenses. An important factor in revenue determination is weather conditions, which can be quantified through the use of heating or cooling degree-hours. For example, during the summer months weather is measured in cooling degree-hours per day, defined as the hourly Fahrenheit temperature minus 75 degrees summed for a 24-hour period. As would be expected, kwh sales of energy increase as cooling degree-hours per day increase. Consequently, electric revenues vary in relation to the severity of the weather.

Expenses are also influenced by external factors. Financing costs, for example, are to a large extent determined by interest rates. Interest rates are highly variable, reflecting economic and political pressures. Even with a solid credit rating, the cost of funds to a borrower is largely a function of market conditions at the time financing is required.

Differences between the actual and targeted values reveal the variability in the Salt River Project's debt service coverage (DSC) ratio.

The relevant sample space is the debt service coverage ratio (target and actual) for 1973 to 1979. Data are as follows:

Year Tar et DSC x Actual DSC x-9 2 1979 1.70 1.73 .0009 1978 1.64 1.65 F 0001 1977 1.56 1.77 .0441 1976 1.54 1.42 .0144 1975 1.62 1.66 .0016 1974 1.74 1.56 .0324 1973 1.95 1.85 .0100

.1035 The "Target DSC" ratio is based on projections of costs and revenue.

and therefore is subject to uncertainty as'hese costs and revenues vary with 3.60

changes in economic and climatic conditions. The "Actual DSC" ratio is calculated after the fact with full knowledge of actual financing costs and operating results during the given year. Considering each revision of the DSC ratio as a component of a sample, the "Target" ratio would be analogous to a sample mean, x. Similarly, the "Actual" ratio could be regarded as a population mean, u . Under these assumptions, the t-test can be utilized to construct confidence intervals.

The t<<test was chosen for this particular application because of the limited sample space. For a few observations, a considerable source of error is introduced and, as a result, the confidence intervals must be broadened.

The difference between the t-test approach and the z-score technique, which assumes a normal distribution, can be seen in the following comparison:

Normal Distribution: z =

o//n Small Sample: t =x s/Wn

-ll where o is the standard deviation of the normal distribution, s equals the standard deviation of the sample, and n equals the number of observations.

This inclusion of s allows the t distribution of a small sample to differ substantially from a normal distribution.

.1035 E (x --P) '= .,1035 and' =.n - 1 = .01725 A one tail t-test is used to determine that with a 99 percent level of confidence, actual debt service coverage will be at least 1.44 if the target is set at 1.70. Calculations are as follows:

(.001) ~/n where x = 1.70 and P = actual DSC ratio:

r .1313392 )

1.70 5.208 [2.6457513 /

161

Financial performance, as measured by the stability of the debt service coverage ratio, has improved. In the fall of 1978, analysis showed I

that the Salt River Project could only be about 85 percent confident that the actual debt service coverage would be above 1.35, the level below which the covenants preclude further issuance of revenue bonds, while the situation today shows a 99.9 percent level of confidence that actual debt service coverage will exceed 1.44 if the target is set at 1.70. This improvement in financial performance, as stated statistically, however, is not necessarily an indicator of the Salt River Project's future financial profile, which will be subject to the increasing variability of certain key factors, such as the condition of the financial markets and the ability of, the Salt River Project to market its excess energy competitively, as well as to sell a portion of its ownership share in the Palo Verde Nuclear Generating Station.

162

APPENDIX B FORECASTING METHODOLOGY

I I

I

FORECASTING METHODOLOGY Introduction The Salt River Project's forecasting methodology is a composite of distinct techniques used to address a wide range of forecasting needs. In previous years, these techniques have been developed upon an extensive data base incorporating demographic, economic, and company-specific data from the early 1960's to the present. Ongoing analysis of these data; however, indicates that structural changes following the 1974 oil embargo have rendered the pre-embargo data obsolete. Accordingly, time series data prior to 1974 have been deleted from consideration. Subsequently, forecasting problems arising because of the limited data appropriate for use have necessitated the development of additional and revised forecasting strategies by the Salt River Project.

The forecasts developed at the Salt River Project, for the most part, are produced by two statistical approaches, which may be broadly categorized as short-term and long-term methodologies. The short-term forecast, which encompasses the first two years of the projection time frame, is produced by monthly Box-Jenkins univariate and transfer function time series models. 1 The long-term forecasts for the next eighteen years of the projection time frame are generated by weighted moving average processes, In the long-term forecast, annual control totals for certain series, which have been determined to be more statistically stable than the series

"'themselves, are estimated from multiple linear regression models.

1 A univariate model is a model developed from the time series of a single variable. A transfer function is a statistical technique by which a time series of a variable can be transformed by independent variables into a new time series, which can then be forecasted. Thus, the impact of outside factors is incorporated into the univariate forecasting process.

163

Additionally, the time series for some variables, most notably for large industrial customers, do not lend themselves to modeling by any statistical method. In these cases, information provided by the specific company concerning its future utilization and expansion plans is combined with growth rate analysis to produce annual forecasts. A more detailed discussion of these approaches, as well as the short-term forecasting methodology, is provided in the following sections.

General Methodolo Descri tion Short-Term Forecastin Methodolo . The short-term forecasting approach at the Sa1t River Project employs a modeling technique, called Box-Jenkins after its authors, that is especially well suited for dealing with the difficulties associated with developing a forecast from limited historical time series. The few years of data desirable for use in forecasting customers, energy, and peak demand produce forecasting models with autoregressive characteristics. That is, values of the variable to be forecasted are dependent on previous values of this variable. The Box-Jenkins forecasting method takes advantage of this autoregressive model behavior to produce a model with the capability of forecasting not only annual totals, but also the monthly distributions for variables which exhibit fluctuating or cyclical seasonal behavior. The methodology, through the use of a transfer function, also allows the inclusion of independent'ariables such as temperature and humidity as explanatory factors in the model. In the Box-Jenkins approach, however, the explanatory variables should not be considered similar to independent or explanatory variables in econometric modeling.

Rather, their nature may be more correctly characterized as that of a leading indicator. For example, two useful leading indicators in the determination of monthly peak demand are residential energy and weather. However, neither of

these variables provides an explanation of why a particular monthly peak demand will be achieved.

In addition to the Box-Jenkins methodology, the Salt River Project's short-term forecasting approach incorporates other methodologies where necessary or appropriate. .Many of the components of the load forecast cannot be modeled with validity by statistical or transfer function techniques even I

though theory, observation, and intuition indicate that a relationship exists'.

In other instances, data may be available which produce an excellent Box-Jenkins model. However, forecasts of the explanatory variables are not available or easily developed. Vhere these problems cannot be overcome with a reasonable cost and time commitment, alternative forecasting approaches are employed.

The weighted moving average forecasting approach utilizes weighted moving averages of post-embargo growth rates to extend the forecast of a variable one time period (either a month or a year) into the future. That forecasted value is then incorporated in the recalculation of the next average growth rate while the oldest data point is deleted from further consideration.

The moving averages utilized in this approach are based upon every possible combination of growth rates present in the data base. For example, with six years of annual data, there are five one-year growth rates, four two-year, compound average annual growth rates, three three-year compound average annual growth rates, two four-year compound average annual growth rates, and one five-year compound growth rate. These growth rates are averaged through the use of an exponential weighting scheme to place greater emphasis on more recent changes in the data. This approach was particularly useful in the development of short-term forecasts for the commercial and small industrial 165

customer and the other customer classes and has been used with some modification in the development of long-term forecasts.

Finally, such components of the short-term forecast as the forecasts for large industrial customers, mines, and agricultural pumping defy all statistical modeling techniques. In these instances excellent forecasts can be achieved through the use of judgmental analysis. Information from individual companies concerning the future utilization and expansion of their facilities provides a basis for estimating future demand and energy requirements. Other requirements, such as for municipalities and sales to other utilities, are based upon direct contact with the utilities or through analysis of contracts. Forecasts for agricultural pumping must be based upon assumptions concerning the weather and rainfall. ln short, each different element for which a forecast must be produced is analyzed to determine the most appropriate methodology available for developing a valid and reliable estimate.

Lon -Term Forecastin Methodolo . The'rojections for the first two years of the twenty-year load forecast are produced through utilization of short-term forecasting techniques. After that time, however, most of the approaches described as short-term have limited application in the forecasting process. In particular, the results of a Box-Jenkins model become deterministic (i.e., base on ratios of monthly and annual changes) once the impact of the original data set is passed. Similar problems also exist with the weighted moving average process if utilized solely as described above.

The long-range methodology at the Salt River Project, therefore, employs an additional technique which, in conjunction with the weighted moving average approach, provides reasonable and valid projections for the remaining eighteen years of the forecast time frame. In this process, future values of 166

a variable that has been determined to be statistically stable, such as an annual total, are projected by econometric and moving average methods'. The monthly distributions for such variables can then be produced through use of the weighted moving average technique. Use of econometric methods, at this point, allows the consideration of independent variables, such as price and income, in the forecasting process.

S ecifi.c Model Descri tions'he preceding descriptions of forecasting methodology are general in nature. In the following sections, models developed to forecast specific series are discussed. Both short-term and long-term modeling procedures are presented under each variable classification.

S stem Peak Demand. The peak demand for the Salt River Project electric system has two components. A large part of hourly demand remains constant throughout the day and year. This portion of peak demand, sometimes referred to as base demand, grows over time in response to growth in the number of electric customers. The other component of peak demand exhibits a highly seasonal cyclical behavior. The hourly magnitude of this portion is determined by weather factors and fluctuations in customer electricity consumption. In the short run, the base component of peak demand should not change radically except in response to unusual phenomena such as employee strikes which would curtail industrial production, or a high level of rainfall, which would reduce the demand for pumping., The stable nature of this base component allows for the development of a Box-Jenkins transfer 2

Peak demand is usually measured as the size of the load averaged over a specified interval of time. The annual maximum demand is the greatest load on an electric system during any prescribed demand interval in a calendar year.

16.7

function model to forecast only the fluctuating patterns of the system monthly peak.

The Box-Jenkins model, which is used to develop the monthly forecast of peak demand for a two-year time frame, originally included residential energy sales and weather variables as leading indicators, or explanatory variables, for the monthly peak demand. However, the significant weather variables that influence peak demand, such as temperature at the time of the peak, relative humidity, and cloud cover, are difficult to forecast and do not necessarily provide good ~ex ost forecasts. This difficulty was overcome by the development of a peak demand forecasting model using only residential energy~ sales as the leading indicator. Residential energy sales are forecasted by the product of the customer forecast and the forecast of residential consumption rates. As the forecast of residential consumption rates is based upon cooling and heating degree-hours, more easily forecasted weather variables, the forecast of residential energy sales carries with it both the impact of customer growth and weather upon peak demand. Residential energy sales also include the impact upon peak demand of commercial and small industrial sales due to the close relationship between commercial and small industrial customer growth and residential customer growth.

Additionally, the use of residential energy sales as a surrogate for customer growth and weather-influenced consumption provides a valuable capacity through which the annual peak demand can be studied after the fact.

The effect of weather on consumption and peak demand can be examined by replicating the forecast using the actual values for cooling and heating 3

A cooling degree is the difference b'etween the actual temperature and 75 degrees Fahrenheit. A- heating degree is the difference between the actual temperature and 6S degrees Fahrenheit. Degree hours are calculated by summing the hourly differentials over a period of time, t such as 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

168

degree-hours in the residential consumption model, and the actual values of residential energy sales in the peak demand model. This allows inspection of the impact of normal, mild, or severe weather upon the peak demand.

The proje tions for the third through twentieth years of the long-range forecast of system peak demand are also developed using residential energy sales as the leading indicator. However, for this part of the forecast, a weighted moving average model is used to forecast the relationship of the annual sum of the monthly system peak demands to annual residential sales. The monthly peak demands can then be distributed according to their relationship to the annual sum.

A second trend is also factored into the forecast for the third through the twentieth years. This trend allows the residential energy system peak demand load factor relationship to increase over the forecast time frame. An increasing load factor produces a dampening effect upon the growth of the peak demand. An increasing load factor is hypothesized to be the result of the combined effects of the cost of electricity to the consumer and conservation efforts. In the future, load management programs and rate structures should prove beneficial in causing the load factor to increase.

Residential Class: Customers and Ener . The forecast of monthly residential customers for= the first, two years of the long-range forecast is achieved through utilization of a Box-Jenkins univariate model. The monthly totals for the first year of the forecast may be adjusted after building permit and vacancy rate data have been fully analyzed.

4.

Load factor is the ratio of the average load in kwh supplied during a designated period to the peak or maximum load occurring in that period.

~

169

Two methodologies are available for forecasting the year-end (for the fiscal year ending April 30) residential customers for the remaining eighteen years of the long-range forecast. The first approach is a regression model which determines- the future relationship between the Salt River Project residential customers and Maricopa County population projections as provided by the Arizona Department of Economic Security. The customer forecast is then analyzed to determine its consistency with household size and population growth rate assumptions included in the county projections. The second approach is to develop the customer forecast from growth rate assumptions.

The growth rate assumptions are developed from analysis of past growth trends in residential customers and the housing market and from analysis of county economic projections provided by various sources. This methodology is especially beneficial in providing various customer growth scenarios.

Once April residential customers have been estimated, the monthly distribution of customers is projected by the weighted moving average method.

This method captures changes in the trend of monthly distribution and allows these changes to affect the forecast.

Monthly residential consumption for the first two years of the forecast is produced by a Box-Jenkins transfer function in which monthly heating and cooling degree-hours are incorporated as explanatory variables.

As this methodology provides the capability of analyzing the impact of weather upon consumption and sales after the fact, it is especially useful in the analysis of variances in the budget.

After the first two years of the forecast, the annual average residential consumption is determined through various growth rate assumptions based upon recent trends and future economic developments. Throughout the forecast the average annual consumption is used in preference to consumption 170

per year-end customer. It has been determined that average annual consumption is a more appropriate statistic b'y which to monitor changes in consumption patterns, especially in light of the changeover at the Salt River Project from a calendar to a fiscal year. The annual consumption is distributed monthly by the weighted averaging process, which forecasts the growth rate of each month relative to the annual growth rate.

Monthly residential energy sales are calculated by multiplying residential customers and consumption rates for each month of the forecast period.

Commercial and Small Industrial Class: Customers and Ener According to economic theory, a strong relationship exists between population and employment in businesses which provide goods and services for local consumption. This theory is also applicable to the relationship between residential customers and commercial and small industrial customers of the Salt River Project.

The forecast of average annual commercial and small industrial customers is generated by a weighted moving average model, which relates the series to that of residential customers. The process, which is based upon the recent historical relationship, then distributes the relative monthly commercial and small industrial customers among the twelve months of the fiscal year, based upon the monthly relationship to the average annual number of customers.

The average annual consumption rate for the commercial and small industrial class is forecasted independently of the relationship to residential customers. A Box-Jenkins univariate model has been developed for the first two years of the forecast, while the weighted moving average approach, as described previously, is used to generate the remaining eighteen 171

years. Energy sales for the class are obtained by multiplying monthly customers and consumption.

t Other Customers Class: Customers and Ener . The customer totals for classes other than residential and commercial and small industrial cannot be forecasted with any precision as individual customer classes. The customers concerned include mines, large industrials, municipalities, street lights, agricultural pumping, interdepartmental and other electric customers.

In some classes, such as street lights, the totals may fluctuate with no obvious seasonal pattern. In other classes, such as mines and large industrials, the addition of new customers is infrequent and cannot be predicted independently with precision. The sum of all other customers by class, however, does exhibit a stable growth pattern. Thus, the aggregate of all these classes is forecasted in the long run. A weighted moving average method is used to forecast the annual average and the monthly totals are distributed from the annual based on their weighted average relationship. For the first two years of the forecast, the various customer classes included in the aggregate are forecasted individually on a monthly basis using ad hoc methods described previously.

The customer totals are not used in deriving energy sales, via consumption rates, as in the residential and commercial and small industrial classes. The customers in most of the other classes are not homogeneous in their size or consumption rates. The .growth in energy sales by class is more stable than is the individual consumption rate, Therefore, energy sales are projected independently from customers and consumption. For some classes, i.e., street lights, regression models using variables such as Maricopa County population have been developed. Forecasts for large industrial customer L

energy sales and demand and mine energy sales and demand are extended several i

172

years by using information provided by the customers regarding their future utilization and expansion plans. The later years in the forecast are developed by applying growth rates developed from analysis of recent trends.

173

174 APPENDIX C PUBLIC UTILITY REGULATORY POLICIES ACT

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PUBLIC UTILITY REGULATORY POLICIES ACT One of the major purposes of the federal Public Utility Regulatory Policies Act of 1978 (PURPA) is to encourage utilities to design rates that are equitable and that promote the conservation of electricity and the efficient use of facilities and resources employed to produce electricity.

Pursuant to this goal, PURPA sets forth certain rate design standards to be considered and either implemented or rejected. Those rate design standards set forth are:

1. Cost of service.

2. Declining block rates.

3. Time-of-day rates.

4. Seasonal rates.

5. Interruptible rates.

6. Load management techniques, In addition to the six rate design standards, the statute includes for consideration a number of other regulatory practices, some of which have rate design implications.

1. Master metering.

2. Automat.ic adjustment clauses.

3. Information to consumers.

4. Procedures for termination of electric service.

5. Advertising.

In addition, a lifeline rate must be considered despite the prohibition against such a rate found in the cost-of-service standard.

For many years, the Salt River Project has been aware of the considerations which underlie the PURPA standards, and has accommodated those

.175

considerations to some extent within its existing rate structures.

Nevertheless, PURPA places on the Salt River Project the obligation to consider each of the standards and the lifeline rates provision. It is vital to a proper understanding of PURPA to realize that Congress has not required the adoption of the standards or of the lifeline rates provision. Rather, the Salt River Project is required to evaluate whether the adoption of the PURPA standards would, in fact, achieve the congressional objectives des'cribed above. In addition, Congress has also declared that the considerations should evaluate the overall appropriateness of adopting the standards.

Congress has specified certain guidelines for the considerations.

The considerations must be made after public notice and public proceedings.

The final determination of whether to adopt the standard must be in writing, based upon evidence presented at the proceeding, and be available to the public. In addition, the determinations must include supporting findings.

Accordingly, on November 5, 1979, the Salt River Project Board of Directors adopted a PURPA implementation plan and procedures for conducting the PURPA proceedings. The implementation plan and procedures are available as separate documents in the Rate Information Room.

On July 21, 1980, the Salt River Project held a proceeding to obtain customer comments regarding the PURPA standards relating to information to consumers, termination of service and master metering. On September 8, 1980, the Board of Directors made determinations regarding these standards. A copy of the determinations is available as a separate document in the Rate Information Room.

Another proceeding was held on September 30, 1980, to solicit customer comments regarding the standards relating to advertising and 176

automatic adjustment clauses. The Board of Directors made its final determinations regarding those standards on November 3, 1980, and copies of the resolutions regarding those determinations are also available in the Rate Information Room.

The current schedule calls for the Salt River Project Co hold a proceeding for the PURPA standards relating to cost of service, declining block'ates, seasonal rates and interruptible rates standards on July 28, 1981, and another proceeding on August 25, 1981 to consider time-of-day rates and load management techniques. In addition, the Salt River Project will be considering the lifeline rates provision on March 16, 1982. The Salt River Project believes that a proper consideration of the rate design standards requires customer load and cost of service data, Hence, dates were selected for the proceedings on the rate design standards which would provide sufficient opportunity to gather and evaluate that data. These dates comply with the time frame set forth in PURPA for consideration of the standards.

177

178 GLOSSARY Accumulated Net Revenues: That portion of capitalization which represents the sum over the years of those dollars remaining after operating costs are met. This element of capitalization essentially reflects ratepayers'quity in the Salt River Project.

Basis Point: One one-hundredth of a percentage point.

Bond Bu er Index: An average of the net interest rates carried by a sample of specific municipal bond issues selected as representative of high-quality, investment-grade debt securities'ublished weekly.

Bond Covenant: A clause in a resolution of an issuer's governing body, pledging the issuer to perform or not to perform in a specific manner.

and publication of descriptive financial data on said issuers. Quality refers to the ability to pay principal and interest in varying economic conditions, and reflects the risk involved for the investor in a given bond. Standard and Poor's uses the following descriptive designations:

AAA--highest quality; AA--high quality; A--upper medium quality. Moody's are correspondingly Aaa, Aa, A.

Bonded Indebtedness: That amount equal to the sum of principal installments due and unpaid at a point in time for all bonds issued and outstanding.

Ca ital Ex ansion: Those dollars planned to be expended in the future on improvements in the electric system comprising generation, transmission, distribution, and general facilities.

Cash Flow: An accounting concept for assessing operating results that concerns itself solely with changes in the actual cash position of a

.179

company--i.e., revenues, expenses (cash), interest income, interest payments, etc.'xcludes accrual noncash items such as depreciation.

Commercial Pa er; Unsecured short>>term (less than 270 days) promissory notes I, traded in a public market.

Commercial Pa er Ratin s: Ratings issued by Moody's or Standard &, Poor's which denote the quality of a given issuer's paper. Ratings range from P-1 to P-3 by Moody's and A-1 to A-3 by S&P. A-1 and P-1 are the highest ratings and are those assigned to the Salt River Project's commercial paper.

Confidence Level: An estimate in statistical inference that states the strength of the conviction that a statement is correct relative to the true state of nature.

Debt Market: All institutions and procedures for bringing buyers and sellers of debt-related financial instruments together.

Debt Ratio: The ratio of total long-term debt to total capitalization (the sum of total long-term debt and accumulated net revenues).

Debt Service Covera e Ratio: The ratio of operating revenues after operating expenses plus interest income to total debt service. For the Salt River Project, this ratio is stated before the extraction of property taxes and support of water operations.

Debt Service Total: For any period, an amount equal to the sum of interest accruing during such a period and that portion of principal installments for the same period.

Demand: The rate of usage of electricity as measured in kilowatts (kw).

Demand reflects the amount of facilities required to serve customers.

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EcCu~it: Refers to invested ownership, and thus for the Salt River Project can be considered as that part of total capitalization other than that represented by long-term debt.

Fuel Ad'ustment: An adjustment applied to energy rates of standard electric rate schedules reflecting increases or decreases in the weighted average cost of fuel and purchased power.

Funds Available for Cor orate Pu oses: That part of operating revenues'fter operating expenses, interest income, total debt service requirements, contributions in lieu of ad valorem taxes and contributions to water operations.

General Obli ation Bonds: A debt instrument which is a lien upon real property included in the Salt River Project Agricultural Improvement and Power District and additionally secured by a pledge of revenues.

Historical Cost: The average cost, of Salt River Project operations as determined from the accounting records of a prior year. Normally expressed in $ /kw, $ /kwh, and $ /customer.

Joint Action A enc  : A financing shell formed by the partnership of several, typically small municipalities or utilities in order to secure the economies of scale available in constructing and financing facilities.

I or, alternatively, the cost avoided in the production of one less unit of output.

Rate of Return Return on Committed Ca ital  : The ratio of net revenues to investors'ommitted capital. Used to determine the relative t profitability of each customer class. Investors'ommitted capital consists of (1) long-term interest-bearing debt net of bond discount and r

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181

expense, (2) accumulated net revenues, and (3) interest-bearing customer deposits.

Revenue Bonds: A debt instrument secured by a pledge of, and a lien on, the revenues of the electric system after deducting operating expenses and subject to prior liens of general obligation bonds.

Total Ca italization: Total investment of the equity holders and debt holders of a business entity, and thus for the Salt River Project, the sum of long-term debt and net accumulated revenues.

182

District Board February 12, 1981 "RESOLUTION APPROVING INCREASES IN ELECTRIC REVENUES FROM STANDARD ELECTRIC RATE SCHEDULES WHEREAS, the Salt River Project Agricultural Improvement and Power District (the "District"), an agricultural improvement district, in conjunc-tion with the Salt River Valley Water Users'ssociation, operates the Salt River Project, a federal reclamation project, providing for the development, storage, transportation and distribution of water within an area of approxi-mately 240,000 acres, both for irrigation and for the domestic, municipal and industrial water supply of those portions of the Cities of Phoenix, Scottsdale, Tempe, Gilbert, Mesa, Glendale, Peoria and Chandler located with-in said area, and WHEREAS, the District supplies electricity at retail wi thin a 2,900 square mile area to parts of Maricopa, Gila and Pinal Counties, which in-cludes approximately 55K of the metropolitan Phoenix area, and supplies elec-tricity at wholesale in a 2,400 square mile portion of Gila and Pinal Coun-ties, and undertakes to serve those desiring electric service and located within the above described areas, and WHEREAS, in keeping with the reclamation principle and laws as applied to the lands of the several western states, the District applies a portion of its electric revenues to reduce the costs of water stored and distributed by it, and WHEREAS, the effects of inflation, increasing costs of facilities, in-cluding environmental costs, increasing costs of capital, fuel, labor and other operating expenses, have caused electric utilities nationwide to in-crease their rates, and have and will cause the District to increase its elec-tric rates, and WHEREAS, Arizona Revised Statutes, Section 45-933.01 (A.R.S.

545-933.01) mandates a statutory procedure for participation by standard elec-tric rate schedule customers and District electors in the adoption of changes in standard electric rate schedules, and WHEREAS, as required by A.R.S. 545-933.01, this Board has approved rules and regulations for the adoption of changes in standard electric rate schedules, and WHEREAS, the Board of Directors (the "Board" ) of the District, having been presented tentative conclusions by Management of the District that pro-jections at that time indicated a need in early 1981 for an increase in stan-dard electric rate schedules, and WHEREAS, this Board, recognizing its obligations to maintain the fi-nancial integrity of'the District, to serve its customers, to honor its cove-nants to bondholders, to establish rates at levels sufficient to meet operat-ing expenses and reserves therefor and debt service requirements, and to hold

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District Board February 12, 1981 rate increases to minimum levels to accomplish these objectives, and further recognizing the interest of its standard electric rate schedule customers and its electors in participating in proposed changes in electric rates, on October 14, 1980, caused the following steps to be taken:

1. Public notice as of December 26, 1980 of proposed changes in standard electric rate schedules.

2. Establishment of January 26 and 27, 1981 for a spe-cial Board meeting with public notice thereof, at which the Board would:

a. Hear Management explain and answer ques-tions concerning the proposed changes in standard electric rate schedules'.

Hear Hational Economic Research Associates, Inc. (HERA) review and make recommendations on Management's report and answer questions,

c. Afford standard electric rate schedule cus-tomers and District electors an opportunity to pre-sent written and oral statements and to ask clarify-ing questions of Management and HERA.

3. Establishment of an Information Room, as of December 26, 1980, at the District's main office, and the de-posit therein of Management's recommendation for proposed changes in standard electric rate schedules, long-range plans, cost studies, budget summary, annual reports, official state-ments and other financial planning information, current and proposed rate schedules and HERA's report to the Board, copies of all such documents having been filed with the Secretary and incorporated herein by reference.

4 ~ Establishment by Management of four customer informa-tional meetings to .be held at various locations in the District's electric service area for the purpose of affording Management an opportunity to explain its need for the proposed rate increase to, and to answer questions posed by, customers regarding the proposed rate increase.

5.. Establishment by Management of an informational meet-ing with industrial electric customer's to afford Management an opportunity to explain the need for, and to answer questions on, the proposed rate increase..

6. Retention of HERA as its consultant for the following purposes:

a. To review Management's load forecasts for demand, energy and customer growth forecasts, and

District Board February 12, 1981 to review cost studies as a basis for designing rates.

b. To determine, independently, future reve-nue requirements for the District and to evaluate Management's recommendation for proposed rate ad-justments and to present its findings, conclusions and recommendations thereon, and WHEREAS, as of December 26, 1980, public notice of the proposed changes in standard electric rate schedules, and the special Board meeting to be held January 26 and 27, 1981, was given by publication in newspapers of general circulation within the District's electric service territory and mailing to its standard electric rate schedule customers, and others, and the opening of an Information Room at the District's main office, a copy of said public no-tice being on file in the Secretary's Office and incorporated herein by refer-ence, and WHEREAS, a special Board meeting was held on January 26 and 27, 1981, at the Adams Hotel, Phoenix, Arizona, at which time the Board formally con-sidered the following:

1. Management's recommendation, copies of which had been previously furnished, for proposed changes in standard electric rate schedules entitled "Financial Anal sis and Rate Schedules for Pro osed Ad'ustments in Standard Electric Rate Schedules Effective March 1 1981', which report is on file in the Secretary s Office and incorporated herein by refer-ence, which stated in part:

a. That, based upon the second quarterly bud-get revision of the 1980-1981 Operating Budget, additional revenues from rate increases are re-quired in the amount of $ 5,641,000 during the period March 1, 1981 through April 30, 1981.

b. That, based on budget assumptions used for the proposed 1981-82 Revenue Requirements Budget, additional revenues from rate increases are re-quired in the amount of $ 57,179,000 in fiscal year 1981-1982.

c. That the additional revenue amounts as stated are needed to cover increases in operating, maintenance and financing expenses resulting from inflation and to meet increases in debt service associated with the District's capital expansion program.

d. That the additional revenue amounts repre-sent a 13.7 percent average annual increase in reve-nues from standard electric rate schedules.

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District Board February 12, .1981

e. That the proposed rate increase would pro-vide at a minimum a targeted debt service coverage ratio of 1.70, a 1.35 debt service coverage ratio being required by covenants with the District's bondholders in order to issue revenue bonds at a parity with existing bonds.

f. That Hanagement recommends that the District comply with the standards set by the Council on Wage and Price Stability, and the pro-posed increases in revenues are in compliance with those standards.

9. That, wi thout the rate increase, the District would receive revenues which would pro-vide a 1.63 debt service coverage ratio in fiscal

, year 1980-1981 and a 1 38 debt service coverage

~

ratio in fiscal year 1981-1982 and, therefore, the District could be subject to a reduction in its bond rating which would impact on its ability to issue revenue bonds to finance construction planned and underway, and the cost, of issuance.

h. That Hanagement has, and is following, a policy of placing all special contract customers on standard electric rate schedules whenever possible.

i. That Hanagement has designed proposed rate structures for standard electric rate schedules based upon its recommendation which represent a reasonable allocation among classes of customers to produce the additional revenues required.

j. That the rate increase proposed is indispens-able to the financial well-being of the District and to reliable and uninterrupted electric service to its customers.

2. NERA's independent report on Hanagement's recommenda-tion, copies of which were previously furnished, which stated in part that:

a. At the present time, HERA is satisfied that the load forecasting methodology used by the District yields results which are reasonable. HERA would, however, encourage expansion of the forecast-ing work to include a separate econometric analysis in order to provide a check of the present method-ology and further insight into future directions of power use.

Di stri ct Board February 12, 1981

b. HERA continues to support Management's use of a target debt service coverage'atio of 1.70.

The proposed rate increase would provide a debt ser vice coverage ratio of 1.66 in fiscal year 1980-1981 and 1.70 in fiscal year 1981-1982, levels which HERA find acceptable.

c. The estimated revenues and expenses used by Management to develop the proposed rate increase are reasonable, given available information. However, to the extent that there are changes made in the 1981-82 Revenue Requirements Budget, HERA urges the Board to reflect these changes in the raCe increase approved.

d. Management's estimates of customers to be added to the system 'and the average use per customer, which were used to develop the proposed rate increase, are reasonable.

e. HERA's comparison of the District's histori-cal expenses to those of comparable utilities re-vealed no significant or unexplained changes in trend. The District continues to compare favorably in many of the measures examined.

f. Based upon NERA's review of Management's pro-posal, HERA recomnended that the Board adjust rates, effective March 1, 1981, to increase fiscal year 1981-1982 revenues by $ 57,)79,000, with the proviso that a lower rate increase become effective sale of a if the portion of the District's interest in the Palo Yerde Nuclear Generating Station, presently under consideration, can be accomplished in time to affect 1981-1982 financial results'ERA also urges that any changes in the 1981-82 Revenue Requirements Budget which would affect the debt service ratio be reflected in the final rate increase approved by the Board,

g. HERA recommends that, given an overall in-crease of 13.7 percent, commercial and small indus-trial rates be increased a maximum of 8 percent, large industrial rates be increased by a minimum of 20 percent and irrigation pumping rates be increased by a minimum of 25 percent, with adjustment of the increase to the residential class as appropriate to effect these recoranendations,

h. In general, the rate structure changes pro-posed by Management move in an economically appropri-ate direction once again. However, NERA continues to

4 District Board February 12, 1981 recommend a more rapid acceptance of marginal cost pricing principles in the design of the District's rates.

3. A report by the District's financial consultant, Smith Barney, Harris Upham 5 Co. Incorporated, on the signifi-cance of debt service coverage in determining and maintaining credit ratings.

4. A status report on compliance by the District with that part of the National Energy Act designated the Public Utility Regulatory Policies Act, as it pertains to the District.

5. The oral and written statements of standard electric rate schedule customers and electors. The written statements have been filed with the Secretary and are incorporated here-in by reference, and HHEREAS, this Board, having duly considered the Management Report and its recommendations, the HERA Report and its recommendations, the Smith Barney, Harris Upham 5 Co. Incorporated report, the oral and written state-ments of standard electric rate schedule customers and District electors, and the responses to questions of Management and HERA, has made the following determination:

1. That, in order for the District to provide continu-ous and reliable service to its customers, issue and sell additional revenue bonds for financing required for electric system additions on a parity with existing revenue bonds and to have the bonds accepted in the marketplace, and to provide for increased operating costs and expenses, a rate increase is required in standard electric rate schedules in amounts which will provide approximately $ 2,000,000 in additional

'revenues in fiscal year 1980-1981 and $ 53,377,000 additional revenues in fiscal year 1981-1982.

2. That the additional revenue amounts will average 12.8 percent annually.

3. That the increase in standard electric rate sched-ules will be-effective April 1, 1981.

4. That a portion of electric system revenues should continue to be applied to reduce the costs of developing, storing, transporting and delivering water for the benefit of all water users within the Salt River Reservoir District, including the portions of the cities and towns located therein. The Board takes note that the Board of Governors of the Salt River Yalley Mater Users'ssociation did on November 3, 1980 increase the assessment and charges for 1

District Board February 12, 1981 water and has increased the assessment and charges for water over the last eight years, and for next year, as follows:

Assessments and Char es in l'omestic Contract Additional Water Townsite Assessment Water Del. Fee Per Acct'hg. Per Per Acre Foot Per Acre Year Per Acre Subdivide>on Other Account S50 HF ~Pum Foot 1973 $ 4.25 $ 7.00 $ 14.00 $ 0.35 $ 1.75 $1 75 $ 7..50 $ 2.125 1974 4.75 8.00 15.00 0 '0 1.75 1.75 8 00 F 2.375 1975 5.75 10,00 18.00 0.50 2.00 2.00 8.00 2.875 1976 7.50 14.00 25.00 0.75 3,75 3.75 12.00 3.75 1977 9.00 20.00 45. 00 1 ~ 30 4. 50 4. 50 14 50

~ 4. 50 1978 10.00 21.00 plus 154/acre 1.30 5.00 5.00 16.00 S.OO 1979 11.00 25.00 plus 184/acre 1.35 5.50 5.50 17.00 5.50 1980 12.00 21.84 plus 154/acre 1.50 6.00 6.00 18.50 6.00 1981 13.50 22.96 plus 164/acre 1.75 6.75 6.7S 21.50 6.75 NOW, THEREFORE, BE IT HEREBY RESOLVED, That the Board has reviewed the proposed Revenue Requirements Budget for fiscal year 1981-1982 and thereby determined that the revenues and income (including investment income) from operation of the electric system will be sufficient to provide all payments and meet all other re'quirements as specified in Paragraph No. 1 and Paragraph No 2 of Section 711 of the Resolution Concerning Revenue Bonds, dated as of it

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November 1, 1972, as amended; and be RESOLVED FURTHER, That the Board approves increases in standard elec-tric rate schedules, effective April 1, 1981, following proper notice, which are forecasted to provide additional revenues of $ 2,000,000 in fiscal year 1980-1981 and $ 53,377,000 in fiscal year 1981-1982, and the Board hereby di-rects Management to work toward the maintaining of a minimum long-term debt service coverage ratio of 1.70 within the parameters set forth herein and to continue to place all special contracts on standard electric rate schedules whenever possible; and be it RESOLVED FURTHER, That the Board approves the standard electric rate schedules presented to it in detail on January 26, 1981 by Management, in-cluding the allocations, structures and designs set forth therein, said schedules to be filed with the Secretary and incorporated herein by refer-ence, provided, however, that a $ 4,000,000 decrease in revenues for fiscal year 1981-1982 be allocated proportionately to all classes of customers; and be it i

District Board February 12, 1981 RESOLYED FURTHER, That the Board approves the modifications in l<anage-ment's recoranendations for the E-80 experimental rate schedule, Residential Time-of-Day Rate without Demand Charge, the E-81 experimental rate schedule, Residential Time-of-Day Rate with Demand Charge, including an increase from 1,000 to 3,000 in the number of customers that may,utilize the experimental rates, and the E-39 standard electric. rate schedule, made by Management in response to comments and information supplied by customers and other inter-ested persons participating in the adoption of changes in standard electric rate schedules, and presented to the Board in detail on February 12, 1981 by Management, provided, however, that said schedules be modified further by the proration of the $ 4,000,000 decrease in revenues for fiscal year 1981-1982; and be it RESOLYED FURTHER, That the revised electric rate schedules sha11 be presented for ratification at the March 2, 1981 Board meeting.

Director Arnett moved to amend the resolution to have the rate in-crease become effective on May 1, 1981. Director Ash seconded, and on voice vote the motion was defeated.

Roll was called on adoption of the resolution, as presented, and vote recorded as follows:

YES: Directors Ball, Conovaloff, Brooks, Schrader, Owens, Jr., Fitch, Finley, Hartman, Burton Jr.,

and President Abel HO: Directors Rogers, Hilliams, Jr., Arnett and Ash ABSENT: Director Hurley The resolution was declared adopted.

Rebasin of the Fuel Ad'ustment

>1r. Perkins explained that the standard electric rate schedule fuel adjustment clause provides for increases or decreases in standard electric rate schedules when the average -cost of fuel and purchased power increases or decreases. Since July of 1979, the cost of fuel and purchased power has been averaging $ 0.009758 per kwh; This amount has been included in the energy rate for all standard electric rate schedules. The base amount of $ 0.006089 per kwh is included in the rate. The difference, $ 0.003669/kwh, termed fuel adjustment factor, is added to each energy rate. The fuel adjustment factor is the difference between average fuel and purchased power cost and the amount included in the rate.'r.

Perkins said that Hanagement recommends rebasing the fuel adjust-ment by adding the current $ 0.003669/kwh to the base amount included in the rate for a new base of $ 0.009758/kwh. The nevi base amount would be included

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District Board March 2, 1981 Mr. McNamara pointed out that the District's Construc-tion E Maintenance (CEM) group estimated the cost of pole work only, but its estimate was $ 5,189,008.27, or 40Ã higher than the low bid. C5M has a full work schedule and does not have the manpower to undertake this project.

Mr. Evans then discussed qualifications of the low bid-der, Seaward Construction Company, Inc., and reviewed con-struction projects they have completed or are currently work-ing on.

Hr. HcNamara concluded by stating that the Power Com-mittee recoranended award of the Palo Verde/Kyrene 500 KY transmission line construction contract to the low bidder, Seaward Construction Company, Inc.

On a motion duly made by Director Ball, seconded by Director Rogers and carried, approval was granted as recom-mended by the Power Committee.

'Hrs. Keck, Messrs. McNamara, Evans, Alexander and the representatives of I.B.E.W. Local 769 left the meeting.

'1981 Electric Rate Increase - Revised Standard Electric Rate Schedules Hr. Pfister reviewed the Board's February 12, 1981 directive to Manage-ment to adjust standard electric rate schedules, effective April 1, 1981, rep-resenting a 12.8% increase which will produce $ 2,000,000 in additional reve-nues in fiscal year 1980-1981 and $ 53,380,000 in additional revenues in fiscal year 1981-1982. Mr. Pfister requested Hr. Perkins to proceed with a review of the revised standard electric rate schedules'r.

Pfister left the meeting.

Hr. Perkins stated that copies of the revised standard electric rate schedules were previously delivered to the Board for review. Using overhead slides (copies of which are in the Secretary's permanent files and incorpo-rated herein by reference, along with the revised schedules), Hr. Perkins re-viewed and discussed the revised standard electric rate schedules, indicating where changes had been made in each schedule to conform to the Board's direc-tive of February 12, 1981.

Hr. Perkins concluded by requesting Board approval to implement the revised standard electric rate schedules, On a motion duly made by Director Ball, seconded by Director Hartman and carried, approval was granted as requested.

(

all si ciao F9)

PVNGS ER-OL SYSTEM DEMAND AND RELIABILITY This table and all other tables and figures in this section for PVNGS present the cumulative data as well as individual data for all participants. Where appropriate (that is, sales and purchases between participants), the cumulative data have been adjusted to prevent duplication.

Information in table 1.1-1 shows that the participants had a combined demand compound growth rate of about 5.6% per annum from 1968 to 1978, and that they anticipate a combined growth rate of 3.8% per annum between 1978 and 1988. Between 1988 and 1992, it is expected that the combined system demand will be growing at an average rate of more than 1170 megawatts per year.

All participants are summer peaking utilities. The electric demand and energy growth rate in the areas served by the parti-cipants can be attributed to a rate of population expansion greater than the national average, increased use of air condi-tioning, and a general trend toward higher per capita use of electricity.

Most of the participants do, not have and do not anticipate hav-ing any interruptible load. SCE includes interruptible loads in its load management reductions, which reduce the peak fore-cast used in SCE planning studies.

Monthly demand and energy requirements for 1981 through 1988 for the combined systems of all participants as well as for an individual participant's systems, are presented in table 1.1-2.

Figures 1.1-1 through 1.1-7 are projected 1987 to 1988 load duration curves for the participants'ombined system as well as for each participant. The anticipated 1987 to 1988 load factor for the combined system is 60.3%, with individual load factors ranging from 57.4 to 70.2%. Analysis of the load dura-tion curves indicates that nuclear energy production can dis-place higher priced coal resources, and that the full potential production of the nuclear units can be used in the combined systems of all participants. The displacement of coal resources

PVNGS ER-OL SYSTEM DEMAND AND RELIABILITY will in turn displace the need for the addition of oil-burning units, such as combined cycle and combustion turbine units.

Thus, the use of domestic coal and nuclear resources will, each in turn, result in the area being less dependent on oil, an expensive and uncertain future energy resource.

All of the participants are members of the WSCC. Part of their membership obligation is to periodically report certain of the above load-resource data to the WSCC for use in various reports and studies. These data are compiled and published annually in the WSCC Summary of Estimated Loads and Resources. The loads and resources for the PVNGS Arizona and New Mexico participants are included in the total for Region III, Arizona-New Mexico Power Area; the PVNGS Southern California participants are included in the totals for Region IV, Southern California-Nevada Power Pool. Figure 1.1-8 shows the geographic boundaries of these areas.

The total annual peak demand and energy requirements for these two areas, as extracted from WSCC reports, are listed in table 1.1-3. These data, compiled from the 1972-1987 report period, pertain to all utilities in the geographical area and therefore are larger in magnitude than the data compiled solely for the PVNGS participants. Table 1.1-4 is a list of the monthly demand and energy requirements for the areas as extracted from the WSCC report for 1982 through 1987.

The loads and resources of SCPPA members except Los Angeles Department of Water and Power are presented in table 1.1-12.

Comparable data for LADWP is presented in table 1.1-1, sheet 3 of 7.

The loads and resources of M-S-R members are presented in table 1.1-13.

Supplement 4 1.1-4 December 1981

PVNGS ER-OL SYSTEM DEMAND AND PKIIN IB RELIABILITY 1.1.1.2 Demand Pro'ections The need for PVNGS and other additional generating capacity rests on the validity of the forecasts made by the participants for their respective loads through 1990. To establish this validity the following topics are addressed:

~ Methodology of forecasting

~ Historical accuracy of forecasting

~ Impact of energy conservation measures December 1981 1.1-4A Supplement 4

PVNGS ER"OL SYSTEM DEMAND AND RELIABILITY This page intentionally blank Supplement 3 1.1-4B July 1981

WIFMM&

P. O.

~le BOX 21666 CIDIBIIMIRIW

'HOENIX'RIZONA 85036 November 6, 1981 ANPP-19 367-EEVB Jr/CAB Director of Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission Washington, D:C. 20555

Subject:

Application for Amendment to Construction Permits Nos. CPPR-141, CPPR-142 and CPPR-143 Palo Verde Nuclear Generating Station Units 1, 2 and 3 Docket Nos. STN 50-528/529/530 File Nos. 81-044-026, 81-056-026

Reference:

Letter dated. October 1, 1981, from Reba M. Diggs, Facilities Program Coordinator, License Fee Management Branch, U.S. Nuclear Regulatory Commission, to Edwin E. Van Brunt, Jr., APS Vice President, Nuclear Projects, Arizona Public Service Company

Dear Sir:

Arizona Public Service Company (APS), as Project Manager and Operating Agent of the Palo Verde Nuclear Generating Station (PVNGS) Units 1, 2 and 3, is enclosing herewith three originals and nineteen copies of its Application for Amendment to Construc-tion Permits Nos. CPPR-141, CPPR-142 and CPPR-143, dated Novem-ber 6, 1981.

The 'enclosed Application seeks the approval of the'ransfer by El Paso Electric Company to the M-S-R Public Power Agency (M-S-R) of a 3.95% undivided ownership interest as a tenant in common with the other Participants in PVNGS, and the amendment of Construction Permits Nos. CPPR-141, CPPR-142 and CPPR-143 to reflect such transfer.

Zn support and as'art of the enclosed Application, APS is sub-F mitting herewith nineteen (19) copies. of the financial qualifica-tions information required by 10 CFR 5 50.33(f) . Also enclosed are twenty-two (22) copies of the environmental information required by 10 CFR Part 51. The environmental information consists of I3re-

Director of Nuclear Reactor Regulation November '6, 1981 Page Two liminary revised pages to the Palo Verde Nuclear Generating Station Units 1, 2 and 3 (Docket Nos. STN 50-528/529/530),

Environmental Report Operating License Stage. The preliminary revised pages to the Environmental Report will be incorporated into the next ER-OL Supplement.

The general information required by 10 CFR 5 50.33 is being submitted under separate cover in the form of revised pages to the Palo Verde Nuclear Generating Station'Docket Nos.

STN 50-528/529/530), General Information, Operating License Application.

With respect to antitrust information, M-8-R at this time has no electrical generating capacity. Furthermore, none of the three members of M-S-R has electrical generating capacity in excess of 200 MW(e) . Therefore, pursuant to 10 CFR 5 50. 33a, information regarding antitrust matters is not required for M-S-R or any of its members.

Based on the referenced letter, which concerns the applicable filing fee under 10 CFR 5 170.22 for a similar" application, APS is submitting herewith the filing fee associated with a Class III amendment. Enclosed is an APS check in the total amount of $ 4800 in full payment of such fee. This amount, is based upon a fee of $ 4000 for amendment of Construction Permit No. CPPR-141, and a fee of $ 800 for amendment of Construction Permits Nos. CPPR-142 and CPPR-143.

Sincerely, Edwin E. Van Brunt; APS Vice President Jr.

Nuclear Projects ANPP Project Director EEVB:CAB:jaw Enclosures

Table l. 1-12 SCPPA MEMBERS LOADS AND RESOURCES (Sheet 1 1 of 1 1 )

IMPERIAL IRIGATION DISTRICT ELECTRIC UTILITY SYSTEM (CALENDAR YEAR)

Page 2 of 2 Actual Pro ected 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 Hydro:

Drop No . 4 Unit 1....... 7. 5 7. 5 7~5 7.5 7. 5 7.5 7.5 7.5 7.5 7.5 7. 5 Drop No. 4 Unit 2....... 7 5 7.5 7.5 7. 5 7.5 7.5 7.5 7.5 7, 5 7.5 7. 5 Drop No. 3 Unit 1...... ~ 3 ~ 75 3 . 75 3 . 75 3.75 3.75 3 . 75 3.75 3.75 3.75 3.75 3.75 Drop No. 3 Unit 2....... 3.75 3 . 75 3 . 75 3 ~ 75 3 .75 3 . 75 3.75 3 75 3.75 3 .75 3.75 Drop No. 2 Unit 1....... 3.75 3.75 3 . 75 3.75 3 . 75 3.75 3.75 3.75 3.75 3.75 3.75 Drop No. 2 Unit 2. ~..... 3.75 3.75 3.75 3 ~ 75 3.75 3.75 3.75 3 . 75 3.75 3.75 3.75 Pilot Knob Unit 1....... 9.0 9.0 9.0 9.0 9.0 9.0 9.0 9. 0 9.0 9~0 9. 0 Subtotal....... ~ ~ ~ .~. ~ 39 39 39 39 39 39 39 39 39 39 39 Oeotherna 1:

Additions {1 ) .. 12 15 18 Nuclear<

Palo Verde 1........ 3.5 3.5 3.5 3.5 3.5 3.5 3.5 3.5 3.5 Palo Verde 2.. ~..... 3.5 3.5 3. 5 3.5 3~5 3.5 Palo Verde 3........ 3.5 3.5 3.5 3.5 3.5 Subtotal...

Other: 33 33 NAP-Parker-Davis........ 33 33 33 33 33 33 33 33 33 SCE-Axis Plant.......... 25 25 25 25 25 25 25 25 25 25 25 Purchases . 40 40 40 40 40 100 100 100 250 250 261 Subtotal 98 98 98 98 98 158 158 158 308 308 319 Total . 452 477 477 53 1 534 597 604 607 760 763 777 Nargin for Reserves/Losses .. 84 86 56 84 70 1 15 102 85 2 17 198 190 Percent Nargin.............. 23 22 13 19 15 24 20 16 40 35 32 pp tnt h thy p rtl lp tl lll n r t r thy ll lnqnr l ~ t l lit r th l. Pr lnr rnllnnh.

Table 1.1-13 M-S-R MEMBER LOADS AND RESOURCES (Sheet 1 of 3)

MODESTO IRRIGATION DISTRICT ELECTRIC UTILITY SYSTEM (CALENDAR YEAR)

Actual Pro 'ected 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 Energy Requirements 1712 1773 1837

( Gwh) o ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 1268 1358 1400 1446 1492 1539 1595 1652 Peak Load (MW).......... 351.7 344 398 414 431 447 465 483 503 523 544 Resources: (MW)

Existing 49.5 49.5 49.5 49.5 49.5 Hydro ~ ~ ~ ~ ~ ~ ~ ~ ~ 54.4 54.2 49.5 49.5 49.5 49.5 Gas Turbine .... 39.0 53.4 98.0 98.0 98.0 98.0 98.0 98.0 98.0 98.0 98.0 Proposed 32.8 32.8 Small hydro( 0.5 6.0 19.4 30.8 32.8 32.8 32.8 Geothermal 82.5 82.5 82.5 82.5 82.5 Harry Allen .... 41.7 83.4 83.4 30.0 125.0 60.0 125.0 90.0 125.0 120.0 125.0 120.0 125.0 ANP P 0 ~ ~ ~ ~ ~ ~ ~ ~ ~ ~

Purchases......... 258.3 236.4 272.2 248.1 218.2 224.6 152.0 151.0 149.0 148.0 144.0 Total o ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 351.7 344.0 420.2 443.3 468.5 486.3 569.8 598.8 626.8 655.8 651.8 Margin for Reserve/ 132.8 107.8 Losses ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 0 22.2 29.3 37.5 39.3 104.8 115.8 123.8 Percent Margin.......... 0 5.6 7.1 8.7 8.8 22.5 24.0 24.6 25.4 19.8

a. Consists of at least seven separate small hydroelectric projects.

b. Addition of additional geothermal, cogeneration, wind, hydroelectric, and coal resources is under study.

0 0

atD Table 1.1-13 0

M-S-R MEMBER LOADS AND RESOURCES (Sheet 2 of 3)

CITY,OF SANTA CLARA ELECTRIC UTILITY SYSTEM (CALENDAR YEAR)

Actual Pro ected 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 Energy Requirements (Gvh) ~ ~ ~ ~ 1609 1754 1858 1959 2052 2142 2234 2326 2415 2516 2612 Peak Load (MW).......... 265.6 297 314 331 347 262 378 394 409 426 442 Resources( ): (MW)

Thermal Geothermal, NCPA.... 60.4 60.4 60.4 60.4 60.4 78.4 78.4 78.4 78.4 Gas Turbine - Cogen .. 5.8 5.8 5.8 45.8 45.8 45.8 45.8 45.8 45.8 45.8 Q I Small Hydro I Black Butte......... 6.8 6.8 6.8 6.8 6.8 6.8 Stony Gorge......... 3.9 3.9 3.9 3.9 3.9 3.9 Large Hydro I V Calaveraso ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 62.0 62.0 62.0 62.0 62.0 62.0 0 Purchases............. 265.6 291.2 261.0 278.0 266.6 224.8 255.6 253.6 268.6 345.1 345.1 Total o ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 265.6 297.0 327.2 344.2 372.8 403.7 434.5 450.5 465.5 542.0 542.0 Margin for Reserve/

Losses' ~ ~ ~ ~ ~ ~ 13.2 13.2 25.8 41.7 56.5 56.5 56.5 116.0 100.0 Percent Margin.......... 4.2 4' 7.4 11.5 14.9 14.3 13.8 27.2 22.6 0

0 Ssacae

Table 1.1-13 M-S-R MEMBER LOADS AND RESOURCES (Sheet 3 of 3)

CITY OF REDDING ELECTRIC UTILITY SYSTEM (CALENDAR YEAR)

Actual Pro ected 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 Energy Requirements 651.8 673.1 690.2 (Gwh). 444.6 481.4 511.2 536.8 562.4 587.9 609.2 630.5 Peak Load (MW).......... 105 113 120 126 132 138 143 148 153 158 162 Resources: (MW)

Thermal 25.0 ANP P ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 8.3 16.6 16.6 25.0 25.0 25.0 25.0 Harry Allen.... ~

5.0 10.0 15.0 20.0 20.0 Geothermal...... 16.5 16.5 16.5 16.5 16.5 Small Hydro 4.0 Whiskeytown..... 4.0 4~0 4.0 4.0 4.0 4.0 Saeltzera ~ ~ ~ ~ ~ ~ ~ 0.9 0.9 0.9 0.9 0.9 0.9 Lake Redding.... 14.0 14.0 14.0 14.0 14.0 Lake Red Bluff.. 14.0 14.0 14.0 14.0 14.0 North Fork...... 6.0 6.0 6.0 6.0 Cottonwood...... 9.0 Large Hydro 18.8 18.8 Calaveras....... 18.8 18.8 18.8 18.8 Purchases......... 105 113 120 117 115.4 115.4 115.4 115.4 115.4 115.4 115.4 Total o ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 105 113 120 126 136.0 155.7 213.6 224.6 229.6 234.6 243.6 Margin for Reserve/ 76.6 81.6 Losses. 4.0 17.7 70.6 76.6 76.6 Percent Margin.. ~ ....... 3.0 12.8 49.4 51.8 50.1 48.5 50.4 U 0

0

PVNGS ER-OL 8!I! )

+~I / ppII >!

~ 'I p qy~

CONSEQUENCES OF DELAY The participants generally rely on a high percentage of resources that are remote from their load areas, with power carried to the load areas over EHV transmission systems. There is a limi'ted number of interconnections between the partici-pants'ervice areas and surrounding systems. Even assuming that the large amounts of power that may be needed are avail-able for purchase, the limited number of interconnections and high use of the EHV tranmission system will make it difficult for those large amounts of power to be transmitted to the participants'ervice areas.

Delays in the construction of PVNGS generating facilities will have the following adverse effects on systems planning and operation.

A. Longer Lead Times - Consistent delays in construction lengthen the lead time required for generation plan-ning. This reduces the flexibility and adaptability of incorporating new technology or changes in load fore-casts into the planning process.

B. Decreased System Reliability - Delays will result in lower reserve margins that decrease system reliability and thereby 'cause more frequent service interruptions.

C. Additional Costs - The delay of a generating facility may require the temporary substitution of a more costly alternative with the possibility of a greater environ-mental impact. Delays also result in additional costs for interest during construction of the planned facility.

The impact of delay on production costs is shown in table 1.3-8. The assumptions regarding heat rate, fuel cost, OM costs, and discount rates are presented in table 1.3-9.

The energy mix of SCPPA members and M-S-R members that have their own generation is shown in tables 1.3-10 and 1.3-11, respectively.

December 1981 1 '~3 Supplement 4

Table 1.3-1 1981 RESERVE MARGIN DUE TO DELAY OF PVNGS (MW) (Sheet 1 of 10)

No 1 Year 2 Year 3 Year Indefinite Delay Delay Delay Delay Delay Arizona Public Service 697 697 697 697 697 1464 1464 1464 1464 1464 El Paso Electric 153 153 153 153 153 Public Service 238 238 238 238 238 of New Mexico Salt River Project 1037 1037 1037 1037 1037 Southern Cali fornia 2197 2197 2197 2197 2197 Edison Participants Total 5786 5786 5786 5786 5786

Table 1.3-9 AVERAGE SYSTEM DATA SOUTHERN CALIFORNIA EDISON (Sheet 6 of 6)

Heat Rate Fuel Cost 0&M Cost Year (BTU/KWH) ($ /MWH) (9/MWH) 1981 9880 42.40 3.50 1982 9850 49.70 4.40 1983 9860 49.20 4.40 1984 10080 '3.60 4.90 1985 10170 58.60 5.30 1986 10290 60.90 6.10 1987 10430 63.80 6.90 1988 10520 65.50 8.10 1989 10560 69.10 8.80 1990 10520- 73.60 9.60

f. SCE discount rate is 15%

PVNGS ER-OL CONSEQUENCES OF DELAY Table 1.3-10 SCPPA MEMBERS ENERGY MIX MEMBER HYDRO GAS DIESEL COAL LADWP ~ ~ o ~ o ~ oo ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ oo ~ ~ o 14$ 27/ 28$ 31$

BurbKko ~ ~ o ~ ~ ~ ~ ~ ~ oo ~ ~ ~ o ~ ~ ~ ~ 3X 72K 25K 0 Glendale.................... 10$ 78/ 12$ 0 Pasadena.................... 17K 72K 11K 0 Imperial Irrigation District 52/ 34/ 14$ 0

a. Excludes members without their own generation.

Table 1.3-11 M-S-R MEMBERS ENERGY MIX MEMBER HYDRO GAS Modesto Irrigation District....... 50.4$ 49.6g City of Santa Clara............... 0 100$

a. Excludes members without their own generation.

Supplement 4 1.3-74 December 1981

M-S-R PUBI IC POWER AGENCY Provide a detailed statement of the projected sources of funds for each municipal applicant's capital con-tribution to the subject project showing both the timing and amounts that will be financed and advanced to the lead ap-plicant for the acquisition of the respective ownership interest. of the facility. State in detail all other con-struction expenditures that are projected to be incurred during the acquisition period, including other capital re-quirements such as sinking fund requirements and redemptions of maturing bond issues. Indicate the expected breakdown between internally-generated funds and external financing during the acquisition period in the meeting of the total capital requirements. Provide a detailed explanation of the assumptions upon which the projected sources of funds state-ment is based. 'l Answer:

It is expected that all necessary funds for the acquisition by the M-S-R Public Power Agency (M-S-R) of a 3.95% undivided interest in PVNGS will be obtained from revenue bonds. The following was assumed for calculating the costs to M-S-R:

Buy-in Date: 5/1/82 Bond Coupon Rate: 12% Average Bond Discount,: 3%

Reinvestment Rate: 12% Average Commerical Operation Dates: PVNGS 1 - 5/1/83 PVNGS 2 - 5/1/84 PVNGS 3 5/1/86 The estimated construction cash flow for PVNGS was provided by Arizona Public Service Company (APS), as Project Manager for PVNGS.

Utilizing the above assumptions and "buy-in" costs as provided 'for. in the "Arizona Nuclear Power Project Assign-ment. Agreement between El Paso Electric Company and M-S-R Public Power Agency" (Assignment Agreement), attached hereto as Appendix A, the total multiple bond issue amount is esti-mated to be 9300,000,000. M-S-R currently contemplates fi-

e nancing this amount by issuing two separate series of bonds.

The bond issues are currently: estimated to be sized and timed as follows: (1) $ 200,000,000, at or around May 1, 1982; and (2) $ 100,000,000, around early 1983.

The amount that M-S-R,will pay to El Paso Electric Company at the closing under the Assignment Agreement is estimated to be $ 165, 000, 000.

Table 1 lists the amounts expected to be advanced by M-S-R to APS after the close of the sale.

Table 1 M-S-R ESTIMATE OF. EXPENDITURES 'TO APS $ 1000 YEAR (July 1 - June 30)

May and June 1982 1982-83 1983-84 1984-85 1985-86 1986;87 Acquisition of 3.95% Own-ership of PVNGS 3,121 15,200 8,844 6,162 2,337 537 Sewage Efflu-ent Payments Preoperation Staffing and Training 96 509 0 3.95% Share of PVNGS Startup Costs 91 2,012 1,610, 1,069 1,486 3.95% Share of Uranium Oxide Procurement, Conversion, Enrichment and Fabrication for PVNGS 578 3, 998 1, 513 3,554 1,417

Cl o

If any municipal applicant is to finance its own-ership share with bonds, indicate the source of funds for payment of interest charges and principal. Indicate the legal authority by which each municipal applicant can issue bonds to provide financial support for the subject project.

Show the effect of any restrictions on both project and total financing ability stating the amount of financing that may be presently performed under such restrictions.

Answer:

M-S-R proposes to finance its ownership share of PVNGS with revenue bonds. The security for such revenue bonds is provided by a Power Sales Contract between M-S-R and those of its members who enter into the Power Sales Contract with M-S-R to acquire the right or entitlement to participate in the capacity and energy output associated with M-S-R's ownership interest, in PVNGS. Attached hereto as Appendix B is a form of such Power Sales Contract. .The City of Santa Clara has decided not to participate in PVNGS.

Accordingly, M-S-R will enter into the Power Sales Contract with the Modesto Irrigation District and the City of Redding and will sell 100% of the capacity and energy output asso-ciated with its ownership interest in PVNGS. The total amounts payable by the M-S-R members participating in PVNGS will be equivalent to M-S-R's its share of the PVNGS operatingdebtandservice requirements and maintenance costs. The Power Sales Contract between M-S-R and the participating members is anticipated to be executed in January, 1981.

Pursuant to Section 5(c) of the Power Sales Contract, the source of payments which would be utilized by the M-S-R mem-ber in paying its obligations to M-S-R would be limited to revenues which such member derives from the operation of its electric system.

The legal authority for M-S-R to issue revenue bonds to acquire an ownership interest in PVNGS is contained in Sections 6500 et sect. of the California Government Code.

M-S-R is authorized by Section 6546 of the California Gov-ernment Code to issue revenue bonds to pay the cost and ex-pense of acquiring or constructing a facility for the gen-eration or transmission of electrical energy and all rights, properties and improvements necessary therefor, including fuel and water facilities and resources.

M-S-R is not aware of any legal restrictions on project or total financing ability at the present time.

Describe the nature, amount, ratings and success of each municipal applicant's most recent revenue and gen-eral obligation bond sales. Indicate the current total out-

'standing indebtedness in each category for each entity.

Answer:

M-S-R is an entity which was created as of April 29, 1980, and at the present time has not issued any revenue or general obligation bonds.

Provide copies of the official statement for the most recent bond issue. Provide copies of the preliminary statement for any pending security issue.

Answer:

M-S-R has not issued any revenue or general obli-gation bonds (see answer to Question 3) and, therefore, has not yet prepared any official statements or preliminary statements.

U 0

Provide copies of the most recent annual financial report and the most recent interim financial statements for each municipal applicant. Continue to submit copies of the annual financial report for each year thereafter as required by 10 CFR Part 50.71(b).

Answer:

To date, M-S-R has not prepared any annual finan-cial reports or any interim financial statements.

Is each participant's percentage ownership share in the facility equal to its percentage entitlement in ex-the electrical capacity and output of the plant? If not, par-plain the difference(s) and any resultant effect on any con-ticipant's obligation to provide its share of design, struction and oper'ating costs.

Answer:

M-S-R's percentage'wnership interest in PVNGS is equal to its Generation Entitlement Share, as defined in the Arizona Nuclear Power Project Participation Agreement, dated as of August. 23, 1973, as amended (hereinafter referred to as the "ANPP Participation Agreement" ). A copy of the ANPP Participation Agreement is provided in the "Palo Verde Nu-clear Generating Station Units 1, 2 and 3 (Docket Nos. STN 50-528/529/530), General Information, Construction Permit Application," Appendices lA and 1B.

o Describe the rate-setting authority of each munic-ipal applicant and how that authority may be used to ensure the satisfaction of financial obligations related to both capital and operating costs of the facility. Describe any restrictions on such rate-setting authority and how this may affect, the applicant's ability to satisfy its obligations to the project. Describe the nature and amount of each munici-pal applicant's most recent rate relief action and the an-ticipated effect on revenues. Indicate the nature and amount or any pending rate relief action(s).

Answer:

Each member of M-S-R which enters into the Power Sales Contract would be obligated to share in the payment of M-S-R's debt service requirements and operating and main-tenance costs in proportion to such member's entitlement of use in the electrical capacity and energy output of PVNGS.

It is not contemplated that the members of M-S-R would con-tribute construction funds to M-S-R.

The members of M-S-R are the California cities of of Santa Clara and Redding and the Modesto Irrigation Dis-trict. The City Council of each city either establishes or approves the electrical rates which are charged to customers of the city's electrical utility. In general, the cities are required by applicable charter provisions, bond covenants or policies of their city councils or boards to establish rates sufficient to recover revenues to pay for the costs of service of providing electrical service to their customers.

The Board of Directors of the Modesto Irrigation District establishes and approves electrical rates for customers of the District. Specific descriptions of the rate-setting authority and the most recent rate relief action for each member of M-S-R participating, in PVNGS and the City of Santa Clara follow.

Cit of Reddin The City of Redding is a general law city; as such, the powers of its City Council are limited, in large part, by California state law.

General law cities are specifically empowered, in Article 11, Section 9 of the California Constitution, to establish, purchase and operate public works to furnish its inhabitants with power. Section 39732 of the California Government Code furth'er provides that legislative bodies (city councils) may, "(a)cquire, own, construct, maintain,

0 and operate . . . works for light, power, and heat Finally, Section 10002 of the California Public Utilities Code provides that any municipal corporation may acquire, construct, own, operate, or lease any public utility.

Specifically, Section 16.12.3'20 of the City of Redding Municipal Code. provides that the City Council shall establish electrical utility rates for all electrical util-ity subscribers. This section further provides that the rates shall be sufficient to pay: (a) for operations and maintenance of the system; (b) for additions and betterments to the system; (c) for amortization of all depreciation and obsolescence within the system; (d) for any and all bonded indebtedness incurred in the construction or extension of the system, including principal and interest; (e) for estab-lishment and maintenance of a reserve fund to provide for extensions and betterments of the system and unforeseen con-tingencies. Redding's rights pursuant to its Power Sales Contract with M-S-R in PVNGS would be a part of the Redding electrical utility. Thus, Redding believes that its finan-cial position wi;th respect to payment of its obligations related to PVNGS is sound and that the financial obligations of the City with respect, to those matters may be met. Red-ding is not aware of any restrictions'n its ability to satisfy its obligations to pay its costs associated with PVNGS.

The City of Redding's most recent rate relief ac-tion, effective July 18, 1978, increased expected annual revenue by 30 percent (.approximately $ 1.6 million). The increase affected average customers as follows:

Customer Class Percenta e Chan e Residential 17.4%

General Service 33.0%

Fixed Rate 28.0%

Street Eighting 28.0%

Commercial Heating 52.3%

General Power Service 48.3%

The increase was undertaken due to increases in the cost of purchased power from the Western Area Power Administration.

Cit of Santa Clara The City of Santa Clara is governed Charter.

Article IV, Section 400,of the Charter providesby that the City of Santa Clara shall have and may exercise all powers necessary and appropriate to a municipal corporation which are not prohibited by the California Constitution. The Con-stitution of the State of California, Article XI, Section 9, expressly empowers cities to operate and maintain an elec-tric utility.

Chapter 10, Article 1, Section 10-1 of the Santa Clara Municipal Code provides that all electrical energy and power furnished to consumers by the city shall be charged, paid for and supplied only according to such schedules, tar-iffs, rules and regulations which the City Council may adopt.. Article VIII, Section 802(3) provides that the City shall have the power to charge equitable rates for the elec-trical services furnished and for building up the properties so as to conserve their value and increase their capacity as needed by the City. Article XIII, Section 1320, provides for the maintenance of a separate Utilities Fund from re-ceipts of operations of the City's utilities. Expenditures from the fund shall be made (a) for various operating ex-penses; (b) for repairs and maintenance; (c) for the payment of interest on bonds issued for acquisition, construction, or extensions; (d) for payment of a percentage of gross re-ceipts of the utilities to the City's General Fund for ser-vices, subject to certain limitations; (e) for extensions and improvements; (f) for the establishment of a sinking fund for the replacement of utilities property; and other expenditures. Section 1321 provides the City Council with the power to authorize the issuance of revenue bonds for the purposes authorized by the general laws of the State of Cal-ifornia.

Modesto Irri ation District Modesto Irrigation District,'s rate-setting author-ity derives from the California Water Code. Section 22115 of that Code empowers an irrigation district to acguire and operate electrical facilities; Section 22117 vests officers, agents and employees of irrigation districts with the same powers, duties, and liabilities respecting electric power as they have respecting irrigation; and Section 22280 provides that. an irrigation district may fix and collect charges for services rendered by the district, including the sale of electric power. The District.'s rates are not subject to any state or federal agency's jurisdiction.

10

0 Modesto Irrigation District's financial obligations relating to both capital and operating costs, including pur-chased power, have been and will continue to be satisfied by rates set by the Board of Directors, pursuant to their au-forth above, for the thority granted by state law as set Irrigation sale of electric energy to Modesto District's consumers. Modesto Irrigation District's rights in its Power Sales Contract with M-S-R related to PVNGS would be a part of the Modesto Irrigation District electrical utility.

Thus, Modesto Irrigation District believes that its finan-cial position with respect to payment of its obligations related to the costs of PVNGS is sound and that the finan-cial obligations of the District with respect to those matters may be met.

The Modesto Irrigation District's most recent rate relief action went into effect on January 1, 1981. The ac-to tion, which increased rates by 15 percent, was undertaken provide additional revenues due to increased costs for pur-chased power.

11

Cl What is the estimated dollar amount that will be payable by the applicant at the date of closing the sale?

What. is the total estimated dollar amount that the applicant will pay to the, lead applicant after closing the sale and through completion of the units?

Answer:

Assuming a closing date of May 1, 1982, the esti-mated amount to be paid to El Paso Electric Company is 8165,000,000.

The remaining construction costs to be paid by M-S-R to APS, as Project Manager, excluding associated interest and nuclear fuel costs, are estimated to be

$ 54,100,000. These estimated costs include all capital costs through commercial operation of each unit.

12

0 Provide copies of the joint ownership agreem'ent.

The Staff will require copies of the executed agreement as a condition of the Construction Permit Amendment,.

Answer:

A copy of the Assignment Agreement in substan-tially the'A. form anticipated to be executed is provided in Appendix A copy of the executed Assignment Agreement will be provided as soon as available. B. A form of the Power A copy of the Sales Contract is provided in Appendix ANPP Participation Agreement is provided in the "Palo Verde Nuclear Generating Station Units 1, 2 and 3 (Docket Nos. STN 50-528/529/530), General information, Construction 'Permit Application," Appendices 1A and 1B.

o 0

0

If a membership organization is participating in J

the joint ownership, explain the contractual arrangement among the members that assures that funds will be available to meet the entity's obligations to the project. Provide copies of the Power Sales Contract.

Answer:

A copy of the form of the Power Sales Contract is provided in Appendix B. Pursuant to Sections 3 and 5 of the Power Sales Contract, M-S-R has obligated itself to issue bonds to provide assurance that funds will be available to meet its obligation to pay for its share of the cost of construction of PVNGS. Moreover, Section 5 of the Power Sales Contract requires the Modesto Irrigation District and the City of Redding which are contracting with M-S-R for an entitlement to participate in M-S-R's Generation Entitlement Share in PVNGS to establish, maintain and collect rates and charges for electric service so as to provide revenues suf-ficient'o pay all amounts when due under the Power Sales Contract. These amounts include amounts adequate to enable M-S-R to pay its debt service and its operating costs re-lating to PVNGS.

The members of M-S-R participating in PVNGS will not contribute construction funds to M-S-R for the purpose of paying for the ownership share of M-S-R. Rather, contemplated that, upon the first to occur of (1) the it is date to which all interest is capitalized with respect to all Bonds and Bond Anticipation Notes, (2) the date which is one year prior to the first principal installment date for any Bonds, or (3) the Date of Firm Operation of the first gen-erating unit, of PVNGS, the participating members would pay a monthly power cost pursuant to Section 5 of the Power Sales Contract. Monthly power costs would include amounts suffi-cient for M-S-R to pay debt service on its bonds and the cost of operation and maintenance of the M-S-R share of PVNGS. The payment to M-S-R by those of its members who enter into the Power Sales Contract for an entitlement of use is an unconditional obligation without respect to whether or not PVNGS is in fact operating or operable. See Section 5 of the Power Sales Contract.

0 Explain the procedure to be used by the lead ap-plicant for billing the municipals for construction progress payments subsecpxent to closing the sale. This may be an-swered by reference to pertinent portions of the joint ownership agreement that is submitted to the Staff.

Answer:

The procedure used by 'the Participants in PVNGS respecting the advancement of funds for the construction of PVNGS is set forth in Section 12 of the ANPP Participation Agreement.

15

0 A'PPENDIX A EPE/M-S-R ARIZONA NUCLEAR POWER PROJECT ASSIGNMENT AGREEMENT BETWEEN EL PASO ELECTRIC COMPANY 10 AND 12 l3 M-S-R PUBLIC POWER AGENCY la 15 16 17 REDRAFT 10/30/81 18 RMI 19 20 21 22 23 24 25 26 27 28

EPE/M-S-R ARIZONA NUCLEAR POWER PROJECT ASSIGNMENT AGREEMENT

1. PARTIES:

The Parties to this EPE/M-S-R Arizona Nuclear Power Project Assignment Agreement (hereinafter referred to as "Assignment Agreement" ) are: EL PASO ELECTRIC COMPANY, a Texas Corporation, (hereinafter referred to as "EPE"), and l0 M-S-R PUBLIC POWER AGENCY, a joint powers agency organized and existing under and by virtue of the laws of the State l2 of California, (hereinafter referred to as "M-S-R"). EPE l3 and M-S-R are sometimes hereinafter referred to l4 individually at "Party" and collectively as "Parties".

l5 2. RECITALS:

l6 2.1. EPE presently owns (i) a 15.8% Generation l7 Entitlement Share and a 15.8% undivided ownership 18 interest as a tenant in common in the Palo Verde l9 Nuclear Generating Station, the Project Agreements.

20 and certain other property and rights provided for, 21 contemplated by or resulting from the Project Agreements, (all collectively hereinafter referred 23 to as "EPE's ANPP Interest" ), (ii) a 15.8%

24 partnership interest in the Palo Verde Uranium Venture (hereinafter referred to as "EPE's PVUV 26 Interest" ), and (iii) a 15.8%, undivided ownership 27 in'hat portion of the ANPP High Voltage n'nterest 28 Switchyard described in Section I.2.1 of Appendix 'I of the ANPP Participation Agreement (hereinaf ter

referred to as "EPE's Switchyard Interest" ).

2.2 EPE desires to transfer and assign to M-S-R a

, portion of EPE's ANPP Interest, EPE's PVUV Interest as held by the Rio Grande Resources Trust, and EPE's Switchyard Interest in the amounts and on the terms and conditions hereinafter stated.

2.3 The ANPP Participation Agreement provides that EPE 8

may assign all or a portion of EPE's ANPP Interest, W

and EPE's Switchyard Interest, without the prior lo written consent of any other Participant, to any l2 person, partnership, corporation, or government l3 corporation or agency engaged in the generation, l4 transmission or distribution of electric energy.

The PVUV Agreement provides that the EPE may assign l5 l6 all or a portion of EPE's PVUV interest without the l7 prior written consent of any other Member, to any l8 person, partnership, corporation or governmental corporation or agency who is or becomes a 20 Participant. F 2.4 M-S-R is a joint powers agency created pursuant to 21 22 the California Joint Exercise of Powers Act, 23 (Section 6500 California Government Code) and the 24 Joint Powers Agreement dated April 29, 1980 between 25 the Modesto Irrigation District, the City of Santa 26 Clara and the City of Redding, and is authorized to 27 engage in the generation and/or transmission of r

28 electric energy.

2.5 M-S-R desires to acquire by assignment a portion of

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EPE's ANPP Interest, EPE's PVUV Interest and EPE's Switchyard Interest in the amounts and on the terms and conditions hereinafter stated.

2.6 Neither Party will be required to construct any new transmission or interconnections, nor will any new transmission or interconnections be required which would not otherwise be constructed, in order to effect the transfer contemplated by this Assignment 10 Agreement.

3 . AGREEMENT:

12 In consideration of the premises and the mutual covenants 13 contained in this Assignment Agreement, the Parties agree 14 as follows:

15

4. EFFECTIVE DATE:

16 4.1. This Assignment Agreement shall become effective 17 upon execution by the Parties.

5. TERM AND TERMINATION:

5.1 This Assignment Agreement shall remain in full force 20 and effect, except as may be terminated pursuant to 21 this Section 5.

22 5.2 If those members of M-S-R electing or required to 1

23 hold an election to, affirm an ordinance approving 24 issuance of bonds or notes to finance the purchase 25 of the Transfer Property have not done so by 26 April 30, 1982 or if M-S-R has not executed the 27 transmission contract or'ontracts referred to in 2S Section 10.2.4 by I1982, the Parties shall meet within ten (10) days to assess progress towards 4

achieving a Closing Date. If, In EPE's opinion,

.reasonable progress has not been made and is not expected, EPE shall have the right to terminate this Assignment Agreement within (10) days after the date of said meeting by written notice to M-S-R.

5.3 If the Closing Data has not occurred by this Assignment Agreement shall terminate at midnight on that date.

10 5.4 If at any time the Parties agree that satisfactory progress is not being made toward the accomplishment 12 of a Closing Date, the Parties may mutually agree to extend any of the dates set forth in Section 5.2 or 13 5.3 hereof or may mutually agree to terminate this 14 Assignment Agreement.

15 16 5.5 If this Assignment Agreement is terminated pursuant to Sections 5.2, 5.3 or 5.4, this Assignment 17 Agreement shall'e of no further force or effect, 18 19 except for the obligations= in Section ll hereof.

6. DEFINITIONS:

20 21 In addition to the other terms defined in this Assignment 22 Agreement, the following terms, whether in the singular or

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i'n the plural, when used in this Assignment Agreement and 23 24 initially capitalized, shall have the meanings as 25 specified:

26 6.1 ANPP Participation Agreement means the Arizona 27 Nuclear Power Project Participation Agreement, dated 28 August 23, 1973, as heretofore amended by Amendment Nos. 1 through 5 and as hereaf ter amended from time

to time.

6.2 The following terms used in this Assignment Agreement shall have the meanings defined in the ANPP Participation Agreement: Arizona Nuclear Power Project, ANPP, ANPP High Voltage Switchyard, Generation Entitlement Share, Palo Verde Nuclear Generating Station, Participant, Project Agreements and Project Manager.

10 6.3 Closing Date means the date of transfer and assignment of the Transfer Property.

12 6.4 Palo Verde Uranium Venture (hereinafter referred to as "PVUV") means the'artnership consisting of the 14 Participants or their respective subsidiary 15 companies organized and established by the PVUV Agreement.

17 6.5 PVUV Agreement means the Palo Verde Uranium Venture 18 Agreement dated as of January 7, 1977, as heretofore amended by Amendment No. 1 and as hereafter amended 20 from time to time.

6.6 Member shall have the meaning as defined in the PVUV Agreement.

23 6.7 Sale Price means the price for the Transfer Property based on the sum of EPE's Sunk Costs, AFUDC associated with such Sunk Costs, and Trust Costs.

26 6.8 Sunk Costs means, the actual recorded cash 27 expenditures for the Transfer Property recorded in Federal Energy Regulatory Commission (FERC} Account 107 and agreed upon expenses incurred by EPE in

connection with the property or ownership interest recorded in FERC Accounts 165, 181, 183, 186, 188, 214, 225, 226, 920, 921, 923, 924, 925, 926, 928, 930.1, 930.2, 931, and 932 on the accounting records of EPE on such date, assuming such accounting is based on acceptable FERC accounting procedures.

6.9 AFUDC means allowance for funds used during construction as defined by. FERC's Uniform System of l0 Accounts Prescribed for Public Utilities and Licensees (Class A and Class B) Electric Plant 12 Instructions, Part 101, Section 3, Paragraph 17 and l3 calculated in accordance with the maximum allowable 14 rate as per FERC Order 561 and compounded as described by FERC Order 561.

16 6.10 Project Interest Rate means an interest rate equal l7 to EPE's AFUDC applicable for the period for which 18 interest is calculated.

19 6.11 Rio Grande Resources Trust means -the trust 20 established through an agreement dated January 4, 1979, between Newton I. Waldman, Esquire, and EPE and as hereafter amended from time to time..

23 6.12 Transfer Property means the following portions of 24 EPE's AHPP Interest, EPE's Switchyard Interest and 25 EPE's PVUV Interest to be transferred and assigned 26 on the Closing Date:

27 6.12.1 A'3.95 percent Generation Entitlement Share 28 and a 3.95 percent undivided ownership interest as a tenant in common in ANPP, the

0 Project Agreements, and certain other property and rights provided for, contemplated by, or resulting from the Project Agreements.

6.12.2 A 3.95 percent undivided ownership interest as a tenant in common in that portion of the ANPP High Voltage Switchyard described in Section I.2.1 of Appendix I of the ANPP 10 Participation Agreement.

6.12.3 A 3.95 percent Partnership Interest in PVUV.

12 6.13 Trust Costs means, the actual recorded acquisition 13 costs and financing charges of the Transfer Property, 14 on the accounting records of the Rio Grande 15 Resources Trust on such date, assuming such 16 accounting is based on acceptable accounting 17 procedures.

18 6.14 Uniform System of Accounts means the "Uniform System 19 20 of Accounts prescribed for Class A and B Public 21 Utilities and Licensees" as presribed and, from time to time, as amended or modified by the FERC or its 22 23 successor.

7. ASSIGNMENT AND TRANSFER OF INTERESTS:

24 25 7.1 Upon the payment to EPE in full of all sums required to be paid by M-S-R pursuant to Section 8 or Section 26 9 hereof, EPE shall transfer and assign or shall 27 arrange for the transfer and assignment of the 28 Transfer Property to M-S-R by the execution of a

document or documents satisfactory in form to counsel for each of the Parties.

7.2 M-S-R shall accept the transfer and assignments made pursuant to Section 7.1 hereof and shall assume and agree to perform and discharge all of the obligations of a Participant and a Member associated with the Transfer Property.

7.3 At any time as either Party may reasonably demand in l0 writing, the Parties shall execute and deliver such documents as may be appropriate to implement this l2 Assignment Agreement, to comply with the ANPP l3 Participation Agreement or the PVUV Agreement or to l4 satisfy requirements established by law or by any l5 mortgage, trust indenture or other financing or 16 security arrangements of either Party.

Se FINANCIAL CONSIDERATIONS:

17 l8 As full compensation, satisfaction and payment for the l9 assignment of the Transfer Property, M-S-R agrees to pay ~

and EPE agrees to accept, subject to the other provisions 20 21 of thi's Assignment Agreement, an amount equal to the Sale 22 Price. The Sale Price shall be payable by M-S-R to EPE 23 as: (i) the sum of $ 1,000,000 on September 23, 1981, (ii) 24 the sum of $ upon the effective date of this 25 Assignment Agreement and (iii) the additional sum of 26 on the Closing Date or such additional sums 27 and dates of payment determined pursuant to Section 9 28 hereof. ~Note: Inclusion of Section 9 is subject to further discussion between EPE and M-S-R.) Said sums are

derived in accordance with Exhibit and are based on the best estimates of the Sale Price available to the Parties. The Sale Price shall be subject to adjustment and appropriate payments made between the Parties following audit of the books and accounts of EPE for verification of the Sale Price.

9. OPTIONAL PAYMENTS:

9.1 M-S-R, upon notification to EPE in writing within lo five {5) days after the sale of bonds or notes as contemplated in Section 10.2.5 hereof, may elect to l2 make the last payment due to EPE pursuant to Section l3 8 hereof in two installments in lieu of the single l4 last payment. If M-S-R elects to make the last l5 payment in two installments, M-S-R shall make said l6 payments as follows:

l7 9.1.1 As partial compensation, satisfaction and l8 payment for the transfer and assignment of l9 the Transfer Property. M-S-R agrees to pay 20 and EPE agrees to accept, subject to the provisions hereof, at least onehalf of the 22 last payment amount no later than 23 business days after 24 9.1.2 As full compensation, satisfaction and 25 payment for the transfer and assignment of 26 the Transfer Property, M-S-R agrees to pay 27 and EPE agrees to accept, subject to the provisions hereof, the unpaid balance of the last payment amount no later than

0 months after the payment made pursuant to Section 9.1.1 hereof.

10. REGULATORY AND OTHER APPROVALS 10.1 Performance by the Parties of this Assignment Agreement is'ubject to the approval, authorization or consent of the U. S. Nuclear Regulatory F

Commission, the 'Contracting Officer of the Department of Energy with respect to certain uranium t0 enrichment contracts and the agreement for delivery of uranium hexaflouride, (each of those entities 12 identified in this Section 10.1), and any other l3 governmental agency whose approval may be required 14 as a result of legislation enacted after the 15 effective date of this Assignment Agreement.

16 10.2 The following approvals, authorizations, actions, 17 consents, or agreements are required for 18 implementation of this Assignment Agreement by 19 M-S-R:

20 10.2.1 Approval, by the Board of Directors of the 21 Modesto Irrigation District, of the 22 issuance and sale of revenue bonds and

.23 notes, or any combination thereof, by 24 M-S-R.

25 ,10.2.2 Approval if required, by the City Council 26 of the Ci ty of Santa Clara, of the issuance 27 and sale of revenue bonds and notes, or any 28 combination thereof, by M-S-R.

10.2.3 Approval if required, by the City Council 4u~

4 of the City of Redding, of the issuance and sale of revenue bonds and notes, or any combination thereof, by M-S-R.

10.2.4 ,Execution'f a contract between M-S-R and Southern California Edison Company, or other utility for transmission service.

10.2.5 M-S-R shall have issued and sold its revenue bonds or its notes, or any lo combination thereof, in aggregate principal amount at least sufficient to make 12 available to it the amount of the payment l3 to be made pursuant to Section or l4 hereof, as the case may be.

15 10.2.6 Authorization to conduct affairs as a 16 foreign corporation in the State of Arizona 17 under Title 10 of the Arizona Revised 18 Statutes, if necessary. EPE and M-S-R also 19 agree that, in the event authorization to 20 conduct affairs in Arizona as contemplated 21 by this Section 10.2.6 is denied to M-S-R, 22 M-S-R and EPE will use their best efforts 23 to arrange an alternate structure for the 24 accomplishment of the transactions 25 contemplated hereby which provides M-S-R 26 and EPE, respectively, the originally 27 contemplated benefits of such transactions.

28 10.3 The approval of the appropriate state regulatory agencies in the States of New, Mexico and Texas may 0

be required for implementation of this Assignment Agreement by EPE.

10.4 EPE and M-S-R each represent and warrant to the other that as of the effective date of this Assignment Agreement no (i) approval, authorization, or consent of any entity, or (ii) action, not identified in Section 10, is required with respect to it for it to fully perform and implement this l0 Assignment Agreement. Each Party agrees it shall use its best efforts to assure that all filing and l2 data collection r'equirements that are necessary to l3 obtain the approvals contemplated by Section 10, l4 hereof, and that are within the control of such l5 Party, shall be completed in an expedient manner as l6 soon as possible so as not to impede the normal l7 processes involved in obtaining such regulatory 18 approvals.

l9 ll. REPAYMENT OF DEPOSIT:

20 In the event this Assignment Agreement is terminated in 21 accordance with Section 5, within thirty (30;. days after 22 such termination, EPE shall pay to M-S-R an amount equal to 23 the initial pre-payment of $ 1,000,000 made pursuant to 24 Section 8 hereof.

25 11.1 If such termination results because the approval 26 contemplated in Section 10.1 hereof was not received from the U. S. Nuclear Regulatory Commission, timely 27'&

application having been made by M-S-R, EPE shall pay interest to M-S-R on said amount from the date of C'l I

I

receipt of the payments under Section 8 hereof until the date of repayment by EPE to M-S-R. Interest applicable to such payment shall be at the AFUDC rate(s) experienced by EPE during the aforesaid period.

11.2 If such termination results because M-S-R has not received, or there shall not have occurred, any of the approvals, authorizations, actions, consents, or 10

,agreements contemplated by Sections 10.2 hereof, then, EPE shall pay interest to M-S-R on said amount 12 from the dates of receipt of the payments under 13 Section 8 hereof until the date of repayment by EPE to M-S-R. Interest applicable to such payment shall 14 be at one-half the AFUDC rate experienced by EPE 15 16 during the aforesaid period.

17

12. GENERAL PROVISIONS:

18 12.1 Nothing in this Assignment Agreement shall be 19 construed to require EPE to obtain the consent of .

M-S-R to any action required to be taken by EPE 20 21 under either the ANPP Participation Agreement or the 22 Project Agreements.

12.2 EPE, as of the effective date of this Assignment 23 24 Agreement, hereby represents and warrants to M-S-R 25 that:

26 12.2.1 EPE, to the best of its knowledge, is not, 27 in any materially adverse respect, in 28 breach of any of the terms of the ANPP Participation Agreement, the Project 1

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Agreements, or the PVUV Agreement. EPE has not received notice (i) that any other Participant is in breach of, or default under, any of such Agreements or (ii) that any event has occurred and is continuing which with the passage of time or the giving of notice, or both, would result in any such Participant being in such breach 10 or default.

l2.2.2 Except for the assignment to M-S-R 12 contemplated hereby, and except as to the 13 lien of EPE's trust indenture, EPE has not 14 assigned, transferred, or encumbered or 15 agreed to assign, transfer or encumber, in 16 whole or in part, any of the Transfer 17 Property to be transferred and assigned 18 hereunder.

19 12.2.3 EPE has full legal authority under the laws 20 of the State of Arizona, and the Project 21 Agreements to make the assignment 22 contemplated in this Assignment Agreement, 23 has taken all actions necessary to be taken by it therefor, and has not done or 25 suffered to be done anything which 26 materially and adversely affects the 27 validity or enforceability of any Project 28 Agreement.

l2.3 M-S-R as of the ef fective date of this Assignment 0

Agreement, hereby represents and warrants to EPE that:

12.3.1 To the best of its knowledge, it is not necessary to. seek a judicial determination

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of legislative or constitutional authority to consummate the transfer and assignment contemplated in this Assignment Agreement or the f inancing thereof by M-S-R.

l0 12.3.2 All filing and data collection requirements needed for the approvals listed in Section l2 10.2 hereof shall be completed in an l3 expedient manner as soon as possible so as l4 not to impede the normal processes involved in obtaining such regulatory approvals.

l6 12.3.3 M-S-R is a legal entity duly organized and 17 validly existing under the laws of the (8 State of California, and has the power and authority to (i) subject to Section ll, own 20 the Transfer Property, (ii) sell the output 21 of the Palo Verde Nuclear Generating 22 Station so acquired to members of M-S-R, 23 and (iii) perform and discharge all of the obligations of a Participant and Member.

25 12.3.4 The execution, delivery, and performance of 26 this Assignment Agreement by M-S-R have-27 been duly and effectively authorized by all requisite action of the Commissioners of M-S-R Commission.

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0 12.3.5 M-S-R will proceed with due diligence and dispatch, in good faith, to negotiate and execute the contract referred to in Section 10.2.4 hereof, and to obtain the approvals referred to in Section 10.2 hereof.

12.3.6 M-S-R will proceed with due diligence and use best efforts'o issue and sell its revenue bonds or its notes necessary for lo M-S-R to make the payment required under Sections 8 and 9 hereof, as the case may l2 be.

l3 12.4 EPE shall provide to M-S-R a copy of the ANPP l4 Participation Agreement, and the opportunity to l5 review and copy each of the Project Agreements, l6 provided that M-S-R shall treat such Project l7 Agreements as proprietary documents and not disclose l8 them without the prior consent of EPE, except as l9 required by law in which case M-S-R shall notify EPE 20 in advance of any such required disclosure.

21 12.5 EPE has not made, and does not make, and M-S-R has 22 not relied, and does not rely, upon any 23 representations or warranties, other than those set 24 forth in Section 10.4 or 12.2 hereof, respecting 25 this transaction, the value of any interest to be 26 transferred and assigned hereunder either at the 27 effective date of this Assignment Agreement or at 28 the time of such transfer and assignment, the validity or enforceability of any Project Agreement,

the title, right, or interest to any property comprising the Palo Verde Nuclear Generating Station, PVUV, or the ANPP High Voltage Switchyard, the status of any of such projects or the existence or absence of any claims by any vendors, contractors or subcontractors providing equipment or services for the construction or operation of the Palo Verde Nuclear Generating Station, for the business of PVUV io or for the construction of the ANPP High Voltage Switchyard. It is the intent of the Parties that M-S-R shall assume its pro rata share of all risks l2 l3 associated with the Palo Verde Nuclear Generating, PVUV, and the ANPP High Voltage Switchyard from and l4 L5 af ter the Closing Date in the same manner and to the same extent as though it had been a Participant, 16 Member or joint owner thereof from their respective 17 18 inceptions.

l9 12.6 At the ef fective date of this Assignment Agreement.,

M-S-R shall furnish to EPE an opinion of counsel 20 21 satisfactory to EPE which states that M-S-R has the 22 authority to enter into this Assignment Agreement, 23 that it is fully enforceable against M-S-R, and that 24 the representations and warranties contained in Sections 10.4 and 12.3 hereof are true and 26 correct. Prior to the transfer and assignment, such 27 counsel shall furnish another opinion satisfactory 28 to EPE that all required approvals, authorizations, consents, and agreements have been obtained and the 8

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Assignment Agreement is still fully enforceable against M-S-R provided, that the enforceability of such Assignment Agreement may be made subject to bankruptcy, insolvency, and other laws affecting creditors'ights generally, and provided further, that availability of the remedy of specific performance or injunctive relief is subject to discretion of the court before which any proceeding 10 therefor may be brought.

12.7 At the execution date of this Assignment Agreement, 12 EPE shall furnish to M-S-R an opinion of counsel 13 satisfactory to M-S-R which states that EPE has the 14 authority to enter into this Assignment Agreement, 15 that it is fully enforceable against EPE, and that 16 the representations and warranties contained in 17 Sections 10.4 and l2.2 hereof are true and 18 correct. Prior to the transfer and assignment, such 19 counsel shall furnish another opinion satisfactory 20 to M-S-R that all required approvals, 21 authorizations, consents, and agreements have been 22 obtained and the Assignment Agreement is still fully 23 enforceable against EPE provided, that the 24 enforceability of such Assignment Agreement may be 25 made subject to bankruptcy, insolvency, and other 26 laws affecting creditors'ights generally, and 27 provided further, that availability of the remedy of 28 specific performance or injunctive relief is subject to discretion of the court before which any

proceeding therefor may be brought.

12.8 Upon the ef fective date of this Assignment Agreement, the "Memorandum of Understanding between El Paso Electric Company and M-S-R Public Power Agency for Sale of a Share of the Arizona Nuclear Power Project", dated September 17, 1981, shall be deemed superceded by this Assignment Agreement in all respects and shall be of no further force and 10 effect.

12.9 The Parties agree that this Assignment Agreement can be amended at any time upon mutual agreement of the 12 13 ~

Parties.

13." BINDING OBI IGATION:

14 15 This Assignment Agreement and the terms and conditions 16 contained herein shall bind and inure to the benefit of the 17 respective successors, assigns, trustees and/or representa-18 tives of the Parties.

19

14. WAIVER:

20 Any waiver by a Party of its rights with respect to a 21 default under this Assignment Agreement or with respect to 22 any other matter arising in connection with this Assignment 23 Agreement shall not be deemed a waiver with respect to any 24 subsequent default or matter. No delay, short of the 25 statutory period of limitations, in asserting or enforcing any right hereunder, shall be deemed a waiver of such 27 right.

28

15. NOTICE:

Any notice, demand or request provided for in this I

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Assignment Agreement shall be in writing and shall be deemed properly served, given or made if delivered in person or sent by registered or certified mail, postage prepaid, to the persons specified below:

EPE c/o Secretary P. O. Box 982 El Paso, Texas 79960 M-S-R Public Power Agency lo c/o General Manager P. O. Box 4060 Modesto, California 95352 l2 The designation of any person specified in this Section 15 l3 or the address of any such person may be changed at any l4 time by ten (10) days notice given in the same manner as provided in this Section 15.

16. SURVIVAL l7 The representations and warranties of the Parties contained l8 herein shall survive the consummation of the assignment and transfer contemplated hereby.

20

17. GOVERNING LAW 21 This Assignment Agreement shall be governed and construed 22 and enforceable in accordance with the laws of the State of 23 Arizona.

24

18. EXECUTION:

25 IN WITNESS WHEREOF, EPE and M-S-R have executed this Assignment Agreement as of EL PASO ELECTRIC COMPANY 27 28 By Title

ATTEST AND COUNTERSIGN:

M-S-R PUBLIC POWER AGENCY By Title ATTEST:

10 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28

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S ACKNOWIEDGEMENT STATE OF TEXAS )

) ss.

County of )

on this day of 19, before me, the undersigned Notary Public personally appeared and who acknowledged themselves to be the and of EPE, and tha t they as such officers, being authorized so to do, executed the foregoing instrument for the purpose therein contained by signing 10 the name of the Authority by themselves as such and 12 IN WITNESS WHEREOF, I hereunto set my hand and official seal.

13 15 16 Notary Public 17 18 My Commission Expires:

19 20 21 22 23 24 25 27 28.

APPENDIX B

A 10-26-81 N5983A M"S-R ANPP POWER SALES AGREEMENT (M-S"R PROJECT AGREEMENT NO. 4)

This Agreement, made as of 1981, by and between M-S-R Public Power Agency, a joint powers agency of the State of California, hereinafter called "M-S-R," and its members Modesto Irrigation District, hereafter called Modesto, and City of Redding, hereafter called Redding, I'itnesseth: that WHEREAS, Modesto and Redding, sometimes referred to herein as "Member" or "Members", wish to authorize M-S-R to undertake to acquire by means of an Assignment Agreement a

'3.95 percent generation entitlement share, and a 3.95 per-cent undivided ownership interest, as tenant in common in the Arizona Nuclear Power Project, herein called "ANPP",

the ANPP Project agree'ment, and certain other property and rights; a 3.95 percent undivided ownership interest as a tenant in common in that portion of the ANPP High Voltage Switchyard described in Section I.2.1 of Appendix I of the ANPP Participation Agreement; and a 3.95 percent partnership interest in the Palo Verde Uranium Venture (PUUV).respec-tively, from El Paso Electric Company and thereafter to transmit electric power resulting from such ownership, to

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the Members all of which is herein referred to as the Project; and WHEREAS the Members desire M-S-R to deliver such elec-tric power to them ox to their account in accordance with the following percentages, hereinafter called Participation Percentages:

Modesto 83.33.

Redding 16.67 100.00%

and WHEREAS the Members are in the'rocess of authorizing M-S-R to issue revenue Bonds in order to undertake the Project, and desire to provide security from their electric revenues for such Bonds; and WHEREAS, the Members have heretofore entered into Project Agreement No. 5 to provide a source of the initial financing of the Project, for which they are to be reim-bursed from the proceeds of the bonds; now therefore the Members and M-S-R agree as follows:

1. Definitions. In addition to the terms defined in the recitals hereto the following definitions are applicable to this Agreement:

.(a) "Agreement" means this M-S-R/ANPP Power Sales Agreement as amended from time to time.

L (b) "Bonds" means bonded indebtedness, loans, letters of credit or any other evidences of indebted-ness issued to finance the Project, and includes addi-tional bonds required to complete the financing of the Project, to acquire fuel for the Project, and to decom-mission the Project.

(c) "Bond Indenture" means any indenture or other instrument pursuant to which (i) securities having the

'benefit of Section 5(b) may be issued or (ii) money, the repayment of which is secured by Section 5(b), may be borrowed.

(d) "Electric System" means all properties and V

assets, real and personal, tangible and intangible, of the Member now or hereafter existing, used or pertain-ing to the generation, transmission, transformation, distribution and sale of electric power and energy, including all additions, extensions, expansions, improvements and betterments thereto and equippings

,thereof; provided, however, that to the extent the Member is not the sole owner of an asset or property, only the Member's ownership interest in such asset or property shall be considered to be part of its Electric H

System.

(e) "Revenues" means all income, rents, rates, fees, charges, and other moneys derived by the Member

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from the ownership or operation of its Electric System, including, without limiting the generality of- the fore-going, (i) all income, rents, rates, fees, charges, or other moneys derived from the sale, furnishing, and supplying of the electric power and energy and other services, facilities, and commodities sold, furnished, or supplied through the facilities of the Electric System, (ii) the earnings on and income derived from the investment of such income, rents, rates, fees, charges or other moneys to the extent that the use of such earnings and income is limited by or pursuant to law to the Electric System and (iii) the proceeds derived by the Member directly or indirectly from the sale, lease or other disposition of a part of the Electric System as permitted hereby, but the term "Revenues" shall not include customers'eposits or any other deposits subject to refund until such deposits have become the" property of the Member.

(f) "Trustee" means the trustee under a Bond Indenture or, if there is no trustee, the party iden-tifj.ed therein as "Trustee" for purposes of this Agree-ment.

(g) "Assignment Agreement" means the agreement between M-S-R and El Paso Electric Company by which H-S-R shall hereafter acquire the Project.

2. ~pur ose. The purpose of this Agreement is to allocate the 'electric power to be made available from the Project to the Members, and to provide a mechanism for the financing of such Project.

3. Construction and 0 eration. M-S-R will use its best efforts to finance, acquire, own, and participate in the management of ANPP and the Project, including the negotiation of the Assignment Agreement, and obtain all necessary authority and rights, and do all things necessary and convenient therefor including, but not limited to, the negotiation of a take or pay or other suitably secured contract with Western Area Power Administration or other utilities for an appropriate Participation Percentage. The Members will cooperate with M-S-R to that end, and may give any and all clarifying assurances by supplemental agreements that may be reasonably necessary in the opinion of M-S-R's legal counsel to make the obligations herein more specific, to satisfy legal requirements and provide security for the Bonds, including, but not limited to, covenants on the issuance of additional indebtedness payable out of Revenues of the Electric System, if any. The obligation of each Member shall be secured only by the Revenues of the Electric System of such Member.

4. Sale of Power.,from Generatin Plant; M-S-R will do all things necessary and possible to deliver the

0 output of the Project to its Members and others in accord-ance with their Participation Percentages, at a point on or adjacent to the Electric System of the Member or such other, and to make all necessary,and'ossible arrangements for transmission of such power over the lines of others, and for additional power required from others as reserves against planned or emergency service interruptions.

5. Rates and Char es. Until Bonds are issued, total costs of the Project not paid by other parties will be paid by assessment from M-S-R to the Members in propor-tion to their Participation Percentages.

(a) Commencing with the commercial operation of the Project, M-S-R shall fix charges based on the anticipated amount of power to be available from the Project to produce revenues not exceeding the amounts anticipated to be needed by M-S-R to meet the total costs of M-S-R, net of payments by others, to provide power from the Project, including but not limited to debt service on Bonds, all other payments provided for under the Assignment Agreement, any other operating, maintenance and replacement costs of the Project, and a reasonable reserve for contingencies, and to repay M-S-R for all other Project costs.

(b) Commencing with the issuance" of Bonds for the Project, but only to the extent that the funds

I

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provided under Section S(a) hereof are not sufficient A

for such purpose and that the obligations under this Section S(b) of the Members are pledged or assigned at the sole discretion of M-S.-R under'ny security agree-I ment for Project Bonds of M-S-R, each Member shall pay to M-S-R or to its assignee (consent to which assign-4 ment is hereby given) an amount equal to such Member's Participation Percentage of the total cost to pay all amounts of principal and interest on the Bonds and all other payments required to be made under the Bond Indenture or other agreement or instrument providing for the issuance and repayment of the Bonds. The obli-gation of this Section S is incurred by each Member for the benefit of future holders of M-S-R Project Bonds and shall commence and continue to exist and be honored by Members whether or not power is furnished to them from the Proje'ct at all times or at all, (which t

provision may be characterized as an obligation to pay all costs on a take-or-pay basis whether or not such Project output is delivered or provided), to the extent that such a provision is, at the sole discretion of M-S-R, included in any security agreement for M-S-R

'Project Bonds.

(c) The Member shall make payments under this Agreement solely from the Revenues of, and as an operating expense of, its Electric System, whether or

not the Project is completed, operable, operating, or

~ ~ 4 retired and notwithstanding the suspension, interrup-

~

tion, interference, reduction or curtailment 'of Project output or .ihe power and energy contr'acted for in whole or in part for any reason whatsoever, to the extent that such a provision is, at the sole discretion of M-S-R, includable in any security agreement for M-S-R Project Bonds. Such payments are not subject to any reduction, whether by offset or otherwise, and are not V

conditioned upon performance by M-S-R or any other Member under this Agreement or any other agreement.

Nothing herein shall be construed as prohibiting any Member from using any other funds and revenues for purposes of satisfying any provisions of this Agree-ment.

(d) ,No Member shall be liable under this Agree-ment for the debts of any other Member.

(e) The Member covenants and agrees to establish and collect, fees and charges for electric power fur-nished through e

facilities'f its Electric Syst'm suf-ficient to provide Revenues adequate to 'meet its obli-.

gation under this Agreement and to pay any and all

'other amounts payable from or constituting a charge and lien upon any or all such Revenues.

(f) The Member covenants and agrees that it shall, at all times, operate the properties of its J

'I

Electric System and the business in connection there-with in an efficient manner and at reasonable cost and shall maintain its Electric System in good repair, working order, and condition.

6. Annual Bud et and Billin Statement. M-S-R will adopt an annual budget pursuant to Section 8.

Members will advance funds to M-S-R concurrent with or in advance of payments by M-S-R for Bond Service or payments to Arizona Public Service Company as operating agent and Project Manager for ANPP.

A billing statement prepared by M-S-R will be sent to the Member not later than the fifteenth (15th) day after the end of the calendar month billing period showing the amount payable by the Member as its Participation Per-centage of monthly costs payable under section 5(a) hereof, for the preceding billing period, the amount payable by such Member as its Participation Percentage of monthly costs payable under section 5(b) hereof for the next succeeding billing period, and the amount of any credits. Amounts shown on the billing statement are due and payable thirty (30) days after the date of the billing statement.

Any amount due and not paid by the Member within thirty (30) days after the date of the billing statement shall bear interest from the due date until paid at an annual rate to be established by M-S-R at the time of the adoption of the annual budget.

0 I

On or before the day five (5) calendar months after the end of each fiscal year, M-S-R I shall submit to the Member a statement of the aggregate monthly costs for such fiscal year. If the e actual montly costs and the Member's Participation Percentage thereof, pursuant to this Agreement or under the Bond Indenture, and other amounts payable for any fiscal year exceed the estimate thereof on the basis of which the Purchasing Participating Member has been billed, the deficiency shall be added to the next suc-ceeding billing statement. If the actual aggregate monthly costs and the Member's Participation Percentage thereof and any adjustment of or credit to the Member's Participation Percentage thereof or other amounts payable for any fiscal year are less than the estimate on the basis of which the Member has been billed, M-S-R shall credit such excess against the Member's next billing statement.

If a Member shall question or dispute the correct-ness of'any billing statement by M-S-R, it shall pay M-S-R, the amount claimed when due and shall within thirty (30) days of its receipt request an explanation from M-S-R. If the bill is determined to be incorrect, M-S-R will issue a 8

4 corrected bill and refund any amount which may'be due the Member.

If M-S-R and the Member fail to agree on the cor-rectness of a bill within thirty (30) days after the Member has requested an explanation, the parties shall promptly

submit the dispute to arbitration under section 1280 et seg. of the Code of Civil Procedure.

7. Obli ation in the Event of Default. Upon failure of the Member to make any payment in full when due under this Agreement or to perform any other obligati.'on hereunder, M-S-R shall make demand upon such Member, and if said failure is not remedied within thirty {30) days from the date of 'such demand, it shall constitute a default at the expiration of such period. Notice of such demand shall be provided to the other Members by M-S-R.

Upon the failure of the Member to make any payment which failure constitutes a default under this Agreement, M-S-R shall use its best efforts to sell and transfer all or a portion of such Member's Participation Percentage of Project output for all or a portion of the remainder of the term of this Agreement. If any part of such output cannot be sold at the section 5{a) price or higher, it shall..be sold and transferred at the best available price.,'f,.all:

or. any portion of the defaulting Member's Participation-Percentage of Project output is sold.=and transferred; the; de'faulting i Member! s share shall: noir be'e'dui=ed;.-;and'-'the'g='<-:=.':,-,,",; -., =.:,

," .'Member:;-shall~ remain'iable to 'M-S-,R'. toay~'th'e -'.full':.amount-"=,".;z.-,.",.Ni

'I of its Participation Percentage of monthly'-'costs;. as= if;:.:such" -....":

sale had not been made, except that such liability, shall be discharged to the extent that M-S-R shall receive payment.

from the transferee thereof.. If such default shall-caus'e I

M-S-R to be in default under the Bond Indenture, M-S-R may terminate the provisions of this Agreement insofar as the same entitle the Member to its Participation Percentage of Project output.. Except for such termination, the obliga-tions of the Member under this Agreement shall continue in full force and effect.

Upon the failure of any'ember to make any payment which failure constitutes a default under this Agreement, or upon termination, and except as transfers are made pur-suant to the foregoing paragraph, the Member's Participation Percentage of each nondefaulting Member shall, to the extent included in the Bonds, be automatically increased for the remaining term of this Agreement pro rata with that of the other nondefaulting Members and the defaulting Member's Participation Percentage shall, (but only for purposes of computing the respective Participation Percentages of, the nondefaulting Members), be reduced .correspondingly; pro-vided,. however, that the sum of'such increases .for any:non-defaulting Member shall not exceed,. without .written" consent of. the nondefaulting Members, an accumulated maximum of 25% ',, .

~

of:,the=nondefaulting Member s original Participation:,'-'Pe'r-':.-'c.';..;.'-'~;;.,',

.= ~,,

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Xf the Member shall fail or refuse to"pay..any amounts due to M-S-R, the fact that other Members have increased their obligations to make'uch payments shall not relieve the defaulting Member of its liability for such

-3.2-

~ ~ S~ Wh' '

payments,

'ff'P a~ and any Members increasing such obligation shall have a right of recovery from the defaulting Member to the extent of such respective increase.

The Trustee shall have the right, as a third party beneficiary, to initiate and maintain suit to enforce this Agreement to the extent provided in the Bond Indenture.

8. Covenant with Res ect to Additional Obli a-tions of Members. The Member shall not issue bonds, notes or other evidences of indebtedness, or cause indebtedness to be issued on its behalf or enter into an agreement to take or to take-or-pay for power and energy from a project, payable from the Revenues of its Electric System superior to the payment of operating expenses of its Electric System, (including monthly costs as defined in the Bond Indenture).

4

9. Transfer, Assi nment, Sale and Exchan e of Power and Ri hts Thereto. Except as provided in para-graph (c) hereof, this Section places no restraint upon any t

transfer, assignment, sale or exchange of Project power or rights thereto, of any Member when such transfer, assign-ment, sale or exchange is for the direct or indirect use of

~ , ~

the:-,customers of its Electric System. With regaid to such:..-

transfers', assignments, sales or exchanges the Member.'.ha's,'..-,,':,'.

1 unfettered rights so far as this Agreement is concerned."'.

As used in this Section, the transfer, assignment, exchange or sale of power includes the transfer, assignment, exchange or sale of rights thereto.

. O (a) As to any other disposition of Project power, any Member may, subject to its obligations. under Sec-tion 5 of this Agreement, transfer, assign, sell or III exchange power to which it is entitled under this Agreement only to (a) the. United States, Western Area Power Administration (WAPA) or (b) others, as provided for in this Section.

(b) Such power not disposed of to WAPA shall be offered first to the other Member for the use of the customers of such other Member's Electric Systems solely.

(c) Any 'such power not accepted by the other Member may then be offered to any person or entity that at no time shall any portion of such I'rovided power be transferred, assigned, sold or exchanged with nonexempt entities as defined in section 103(b) of the Internal Revenue Code of 1954,, as amended, including WAPA, unless in the opinion of bond counsel for M-S-R such transfer, sale or, exchange will not cause any 1

Bonds issued with respect to the Project to be treated as industrial revenue bonds with'in the meaning of" sec--

V tion 103 (b) of the. Internal Revenue Code of 1954 - as amended, and subject to federal income taxes.

(d) The Member receiving power under para-graph (b) above shall pay the transferring Member for such power .an amount not more than the cost of such

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a 1 power.-.to such .transferring Membex under Section&.og ..

this Agreement plus all other costs of such Member related to such transferred power.

(e) To the extent not prohibited by existing contract no Member shall purchase power from any other source exclusive of its own generating projects if power is available under this Section at lower cos't, to the extent of such availability and any other Member receiving power by transfer, assignment, sale or exchange hereunder shall agree to'the same restriction as a condition of such receipt.

(f) Upon request M-S-R will arrange such trans-action under this Section as is desired by a Member.

(g) No Member shall transfer ownership of sub-stantially all of its Electric System to another entity until it has first complied with the provisions of this subsection. A consolidation with another govern-mental entity or change in governmental form is not deemed a transfer of ownership.

(1) Before the, date of such transfer, the rights. of the transferring Member under this

• Agreement shall have been disposed of by transfer, 0

assignment, sale or exchange pursuant to provi-sions of subsections (a), (b), (d) and (e) of this Section 9, and subject to the limitations of 1

I

~ .~~2K%I ~ \ ~ I, lWlA WA subsection 9(c), effective as of the date of the transfer.

(2) Such disposition of power must be under terms and conditions that provide assurances to the holders of any outstanding Bonds secured by the Revenues of the Electric System of the Member which is transferring ownership of its Electric System at least equivalent to the pledge herein of such Revenues, in order that M-S-R's obliga-tions under this Agreement, and under the Assign-ment Agreement, and under Bond, Indentures for the Project, and under other agreements made or to be made- by M-S-R to carry out the Project, may be promptly and adequately met. M-S-R may require that sufficient moneys to discharge such obliga-tions be irrevocably set aside and maintained in a trust account, as a condition to the transfer of the Electric System, if no other adequate assurance- is available.

. (h) No transfers, assignments-, sales or exchanges shall diminish any Member's Project allocation without.

1 its consent, except in- the. case of a"'Member. which se'lls:-.

its Electric System, and then only as provided zn-'sub-section (g), and except as provided in Section 7.

10. Insurance and Indemnification. M-S-R will obtain comprehensive and 'adequate casualty insurance on S

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this Project. M-S-R shall also indemnify and hold harmless lan 'l e 0 I+' t,le e r + ate 0%i'o~sew ~%' Is 'why, ~hhw 4s44e4oa~~ete 4'4 ~'WJ4~leb4Ahebssw liability

~ ~4 its Members from any 0 ~

.'4v for bodily injury or property ~

damage resulting from any accident or occurrence arising out of or in any way related to its construction and opera-tion of such Project, and shall obtain insurance for such indemnification agreements in limits fixed by M-S-R.

ll. Decisions. All decisions and expenditures by M-S-R under-this Agreement shall be made in the manner provided for decisions and expenditures in the joint powers agreement creating M>>S-R.

12. Term. This Agreement shall nct take effect until it has been executed by M-S-R, Modesto, and Redding.

The term of this Agreement shall continue until all Bonds issued have been retired, or full provisions made for their retirement, including interest until retirement date, or the M-S-R interest in the project is terminated, whichever is later.

13.,

"e Termination and Amendments. This Agreement shall'no't be subject to termination by any party. under any circumstances, whether based upon the default of any other party"under this Agreement, or any other instrument,- or..

otherwise, except as specifically provided herein.

e ~ ~

So long as any of the Bonds are outstanding and; unpaid or funds are not set aside for the payment or retire-ment thereof in accordance with the Bond indenture, this Agreement shall.not be amended, modified or otherwise

changed, or rescinded, by agreement of the parties:, (i) in any manner that will have a material adverse effect on the payment of the principal of and premium, if any, and interest on the Bonds as they, respectively become payable, (ii) in any manner that would limit or reduce the obligation of the Members to make payments pursuant to this Agreement, or (iii) without the consent of the Trustee. In this regard, M-S-R shall cause notice of the proposed execution and delivery of any such amendment together with a copy of the proposed amendment. to be mailed by first class mail, postage prepaid, to the Trustee at least fifteen (15) days prior to the proposed date of execution and delivery of any such amendment. The Trustee shall be deemed to have con-sented to the execution and delivery of any such amendment if M-S-R does not receive a letter of protest or objection thereto signed by or on behalf of the Trustee on or before 4:30 o'closk P.m., local time, at the principal office of M-S-R, on the fifteenth (15th)'ay after the mailing of said notice and a copy, of the proposed amendment.

14. Liabilit of M-S-R Members. M-S-R is enter-ing into the Assignment Agreement provided for herein for the exclQsive benefit of its members. The debts, liabili-ties and obligations assumed by M-S-R under the Assignment Agreement are not the debts, liabilities and obligations of such participating members, or any other me'mber of M-S-R, and such participating members are bound only by the terms

0 of this agreement between them and M-S-R. In addition, M-S-R agrees that the M-S-R member City of Santa Clara is not a party, third-party beneficiary, assign or otherwise i

interested in or subject to the claims, debts, obligations, judgments,"suits, liabilities, rights or benefits arising under the terms of the Assignment Agreement. Furthermore, in consideration of the sum of $ l0.00 paid to each of the undersigned by the City of Santa Clara, receipt of which is hereby acknowledged, M-S-R ag'rees to release the City of Santa Clara from any claims, demands or liabilities which M-S-R now has or which may hereafter accrue on account of or in any way arising out of this agreement or the Assign-ment Agreement.

IN WITNESS WHEREOF each Member has executed this Agree-ment with the approval of its governing body, and caused its official seal to be affixed and M-S-R has authorized this Agreement in accordance with the authorization of its Commission. "

M-S-R PUBZIC POWER AGENCY MODESTO IRRIGATION DISTRICT By By and and CITY OF REDDING By and'19-