ML063190443
| ML063190443 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 11/07/2006 |
| From: | Bauer S Arizona Public Service Co |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| 102-05592-SAB/TNW/CJJ | |
| Download: ML063190443 (148) | |
Text
Scott A. Bauer Tel. 623-393-5978 Mail Station 7636 Palo Verde Nuclear Department Leader, Fax 623-393-5442 PO Box 52034 Generating Station Regulatory Affairs e-mail: sbauer@apsc.com Phoenix, Arizona 85072-2034 102-05592-SAB/TNW/CJJ November 07, 2006 ATTN: Document Control Desk U.S. Nuclear Regulatory Commission Washington, DC 20555-0001
Dear Sirs:
Subject:
Palo Verde Nuclear Generating Station (PVNGS)
Units 1, 2, and 3 Docket Nos. STN 50-52815291530 Submittal of 2005 Annual Financial Reports Pursuant to 10 CFR 50.71(b), enclosed please find copies of the 2005 Annual Financial Reports for the Participants who jointly own PVNGS and do not file a Form 1 0-Q with the Securities and Exchange Commission or a Form 1 with the Federal Energy Regulatory Commission. These Participants are Salt River Project, Southern California Public Power Authority, and Los Angeles Department of Water and Power. The remaining Participants who jointly own PVNGS file a Form 1 0-Q with the Securities and Exchange Commission or a Form 1 with the Federal Energy Regulatory Commission and are thereby exempt from filing an Annual Financial Report. These Participants are Southern California Edison Company, El Paso Electric Company, Arizona Public Service Company and Public Service Company of New Mexico.
No commitments are being made to the NRC by this letter. Should you have any questions, please contact Thomas N. Weber at (623) 393-5764.
Sincerely, E n clo s u re
?
-Z T
U e '
SAB/TNW/CJJ/gt cc:
B. S. Mallett NRC Region IV Regional Administrator (w/o Enclosure)
M. B. Fields NRC NRR Project Manager (w/o Enclosure)
G. G. Warnick NRC Senior Resident Inspector for PVNGS (w/Enclosure)
A member of the STARS (strategic Teaming and Resource Sharing) Alliance Callaway 0 Comanche Peak a Diablo Canyon & Palo Verde 0 South Texas Project
- Wolf Creek
Los AngeleS Diepartment of Water and Power 2004-2005 Annual Report
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a way of jlife e
Los Angeles,Departme'nt of Wa*er and Power 2:004-2005 Annual Report Ta b le of Board of Water and, Power Cdommi ssioners M. eSsag(e1 rom*the Genro Manger f Revenue & Expen'ndit ure:Do6lar1 I /Coparativo Highlights 3
Highlights of Fiscal Year 2004-2005 4
Water and Energy Facts in Brief, II Water Services Selected Financial Data and Statistics 12 Energy Services Selected Financial Data and Statistics 13
Board of Water and Power Dominick W. Rubalcava Sid. C. Stolper PRESIDENT VICE PRESIDENT Annie E. Cho Gerard McCallum Silvia S aucedo
2004-2005 Annual Report A Message from the General Manager The Los Angeles Department of Water and Power is one of the country's premiere water and power utilities-serving more than 3.9 million customers with reliable, high-quality water and power day and night, day after day. This is what we do best.
The foresight and dedication of many generations of skilled workers has turned this utility into a community leader. LADWP provides the City of Los Angeles with services that these days are often taken for granted. We take pride in the notion that at the start of each new day our customers expect that their lights will turn on and their water will flow. Over the past 100 years, we have proven that reliable water and power is something to be expected and we have delivered.
But being a community leader isn't just about doing what's expected of you. We consider it our responsibility to give back to the City. This philosophy can be seen throughout the Department, but is particularly reflected in our continuing practice of providing a dividend to City residents in the form of a transfer to the City's General Fund. The transferred funds are used to help finance vital City services such as police and fire protection, libraries and recreational facilities.
This past year, LADWP transferred $190 million to the fund-seven percent of the utility's gross power revenues and five percent of the gross water revenues.
This past year, we also continued our commitment to maintaining stable retail electric rates for our customers by securing long-term, stabilized supplies of natural gas. LADWP spearheaded a
$300 million purchase agreement with Anschutz Pinedale Corporation in Denver, Colorado, to buy a portion of the company's natural gas reserves in Sublette County, Wyoming. The gas reserves will provide Los Angeles with a firm supply of natural gas at a stable price to fuel in-basin generating stations and further stabilize this single most volatile component of LADWP's operating expenses. Besides the gas reserves, LADWP also hedged approximately 30 billion cubic feet of gas consumption with financial instruments saving our customers nearly $30 million during the fiscal year.
As a way to better communicate with our diverse communities and to provide a more transparent view of our operations, we signed a Memorandum of Understanding (MOU) with the City's Neighborhood Councils. The MOU is an agreement designed to foster citizen participation, increase responsiveness to local needs, and establish direct lines of communication with Neighborhood Councils. These stakeholders now receive notification of and have the opportunity to review and provide their input on the policies, programs and issues of concern that impact their communities. The MOU is now being used as a model for other City departments.
As the Department's newly appointed general manager, I do not plan to stop with what's expected of me. Each of us, employees and customers alike, has a stake in this company. I plan to do what it takes to maintain the faith our employees and customers have in this great organization for generations to come.
Ronald F. Deaton
Revenue and Expenditure SfBo F
0"?O Residentiol 39%
I Multi-dwelling units 30%
Purchased 4
water 12% /
Operating and S]rmaintenance 37%
Transfer to the City4%y Debt service\\
Capital irmprovements costs 11%
_36%
Industrial 4%
Cammercial 19%
Operating and maintenance 28%
Street lighting 1J/1" Other I%
N.
Si:
Industrial 9%
Re Comparative Year ended June 30 Contv-ercial 57%
sidential 32%
Purchased energy' 24%
Fuel 19%
Transfer to the City 6%
,f Capital irpravments Debt service casts 8%
15%
WATER POWER
% Increase
% Increase 2005 2004 (Decrease) 2005 2004 (Decrease)
SERVICE Sales Customers -, average number (thoUsannds)
FINANCIAL Revenue A Operating Costs 0)
Increase in fund net assets Transfers to City of Los Angeles Capital additions, net Net utility,plant Capitalization -
equityand long-term debt 19 GALLONS IN BILLIONS 191.5 200.8 (4.6%)
664.0 662.0 0.3%
KILOWATT HOURS IN BILLIONS 25.4 25.0 1.6%
1,437.3 1,428.4 0.6%
IN MILLIONS
$ 574.7
$ 596.3 387.3 421.6 38.4 18.6 29.8 27.6 278.0 285.7 3,198.8 2,993.0
,,3,330.1 3,108.9, (3.6%)
(8.1%)
106.5%
8.0%
(2.7%)
6.9%
7.1%/
$2,373.9 1,835.6 10.8 160.2 378.9
.5,229.0
,7,542.4 IN MILLIONS
$2,397.0 1,757.6 50.5 210.2 547.5 5,165.1 7,407.4,
(1.0%)
4.4%
(78.6%)
(23.8%)
(30.8%)
2.6%'
-1.8%
(A) Includes other income and expenses - net; (B) Excludes depreciation expense and loss on asset impairment and abandoned projects; (C) Excludes advance refunding bonds 3
2004-2005 Annual Repori Highlights of Fiscal Year 2004-2005 Deaton Appointed During the-2004-2005 fiscal year, LADWP continued to fulfill its mission of providing reliable, high-quality and affordable water and'
,energy services-in an environmentally responsible manner to the City's 3.9 millioh residents. Having served the City of Los Angeles for more than a century, we understand and embrace our commitment to our customers, communities and the environment.
WATER EFFICIENCY Inside the Home...
Check for leaks regularly and repair leaky faucets, showers and toilet tanks.
A toilet leaking one gallon per minute wastes $2oo in water per month.
Inside the Kitchen...
If every Amcrican were to install a faucet aerator, 25o million gallons of water would be saved every day.
Normal faucet flow is 3-j gallons of water per minute.
By attachrng; a low-flow faucet aerator, flow can be reduced by jo%.
,In December 2004, LADWP welcomed new leadership with the appointment of General Manager Ronald F. Deaton. Deaton served in the City's Chief Legislative Analyst's Office since 1976 and as the City's chief legislative analyst from 1993 to 2004, providing legislative and financial advice to the City Council. Having begun his career at the LADWP in 1965, Deaton returned to lead the Department fqllowing the-resignation of David Wiggs.,
At the Board of Water and Power' Commissioners meeting where his appointment was approved, Deaton said "I am very pleased and honored with this opportunity to lead LADWP as we enter a new era of increasing community outreach, expanding renewable power resources, and meeting the growing demand for water resources.
And on a personal note, I must say I love the City of Los Angeles-and themost precious resource of the people of the City, the LADWP.'"
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2004-2005 Annual Report Highlights of Fiscal Year 2004-2005 Hay es Genera ing Station Repowered The LADWP's generating stations, bastions of energy production during the State's energy crisis, are being modernized through "repowering" to operate cleaner, more efficiently and more reliably. During fiscal year 2004-2005, we completed the modernization of two 1960s era generating units at Haynes Generating Station, located in Long Beach. The generating station provides 575 megawatts of clean, fuel-efficient energy and is now 94 percent cleaner and 40 percent more fuel-efficient. This power plant, along with previously repowered Valley Generating, Station, received a Project Achievement Award from the Los Angeles Council of Engineers and Scientists.
The repowering of Haynes Generating Station was a $375 million project and a major component of LADWP's $1.8 billion Integrated Resource Plan (IRP). The IRP serves as a blueprint for meeting the City's energy demand through emission reduction, demand-side management, developing renewable resources and promoting new, clean electric technologies and energy efficiency.
ENERGY EFFICIENCY Inside the Home...
Setting a thermostat to keep air conditioning at 781F when hot outside, and a heating system at 68'1F when cold, can help save up to 2o% in heating and cooling costs.
Inside the Kitchen...
A load of dishes cleaned in a dishwasher requires 57%
less water than washing dishes by hand if the water is left running. But, if a wash and rinse basin is filled instead of letting the water run, half as much water is used compared to the dishwasher.
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2004-2005 Annual Report Highlights of Fiscal Year 2004-200 5 Renewable Portfolio Standard Adopted WATER EFFICIENCY Inside the Bathroom...
Take shorter showers.
One to two years of drinking water is consumed every week by a family of' four taking five-minute showers each day.
Inside the Laundry Room...
Wash fuill loads or ad fast the water level to match smaller loads& Over-loading will give unsatisfacaory results and require a second wash.
In an effort to increase the availability and use of clean, renewable energy, LADWP established the Renewable Portfolio Standard (RPS). This standard sets a goal of increasing our supply of energy from renewable resources to 20 percent of the generation mix by the year 2017, with an interim goal of 13 percent by 2010.
The RPS reflects our commitment to renewable resource supply and our goal to continually provide the residents and businesses of Los Angeles with reliable, uninterrupted power at competitive rates.
The first RPS-specific project to receive approval by the Board of Water and Power Commissioners is the Pine Tree Wind project-a new energy-generation facility that will provide up to 120 megawatts of wind power for the City. The project will be the largest municipally-owned wind plant in the nation and will provide enough energy to power approximately 56,000 homes per year. Located in the southern Sierra Nevada Mountains, the project is expected to lower emissions of nitrogen oxide by at least eight tons per year and emissions of carbon monoxide by at least 11 tons per year.
6
200/4-2005 Annuo Rep of Fvsc,-l Yearv 2004-200 Highlights Sy mar Converter Station Rededcate The LADWP and the City of Los Angeles,.
together with co-owners Southern California Edison and the cities of Burbank, Glendale and Pasadena, completed a $118 million upgrade to theSylmar Converter Station.
The upgrade involved replacing outdated technology and consolidating the facility into one location.
The Sylmar Converter Station is the southern terminus of the 846-mile Pacific DC Intertie, one of the world's longest and highest rated transmission lines. The facility receives hydroelectric power from the Pacific Northwest in the summer when energy load in the Southwest peaks. During the winter, when the energy demand peaks in the Northwest, excess energy is sent northward. The upgrade of this facility ensures reliability of the LADWP power system' LADWP has' more than 7,000 megawatts of capacity, and typically serves a peak demand of 5,600 megawatts during the summer months.
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I, ENEkGY EFFICIENCY Inside the Bathroom...
A *a* h*arer accounmt for abonr 20Q of a l*olm's daily Inr, By rcducinn the tlermosrat to i ýetss, el of hewan*:s hotrins rnrsgy will Inside the Laundry Room...
Flsctric washer and dryers ran ar'onni: for ai m~uch as a5%
tof on at horm. Try 55p jim5t~55g with cold wawr wash and :ino: c csj Foer o oil:y a'll dlotrs, rhe sults wi be as good as hot waret wash and warnm rnsc, and eneeey can be c:
tn ip i 11 11 7
2004-2005 Annual Reporl Highlights of Fiscal Year 2004-2005 Eastern Sierras Receive Above Average Snow Pack The winter of 2004-2005 brought record 'rainfall to Southern California and persistent storms created the highest snow pack in a decade in the Eastern Sierra watershed, a significant source of the City's water supply. The snow pack had water content equal to 167 percent of normal, guaranteeing an ample supply of less expensive, high-quality water for the year. As a result, LADWP delivered a greater volume of the City's water needs through its own water source rather than purchasing more costly water from the Metropolitan Water District (MWD).
In addition to the increased supply of water, the deep snow pack enabled LADWP to generate an additional 140,000 megawatt-hours of clean, renewable hydroelectricity from its 14 hydroelectric power plants located along the Los Angeles Aqueduct.
WATEK EFFICIENCY Outside of the Home...
At lwast half of the total water consumed in the home may be used outside the house. Be sure to adjust the sprinkler water so that it lands on plants instead of on concrete or other paved areas.
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2004-2005 Annual Report Highlights of Fiscal Year 2004-2005 WPb 3resence Inp oved
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~~~~~~~A ttt Po to ~niI Aos Ao ernsts 4-The LADWP successfully implemented a more informative and customer-friendly presence on the World Wide Web. The new LADWP Web site at www.ladwp.com was designed to improve the speed and efficiency of customer transactions while providing the public with general utility and environmental information.
Customers now have the ability to conduct many transactions on-line, such as having services turned on and off and also viewing and paying bills. The Web site is organized into eight easy-to-use areas that include: Customer Service, Rebates and Programs, Water, Power, Green LA, Doing Business, Community and Safety and About LADWP. New online systems also allow us to provide streamlined service transactions, while enhancing the efficiency of our utility's customer services unit. The Web site also offers many helpful conservation tips and information on LADWP's customer rebate and utility programs.
ENERGY EFFICIENCY Outside of the Home...
Each year, Americans buy an estimated 2.7 million light bulbs just to illuminate porches and backyards. Consider using c*aopacet fluorescent bulbs outside. T[beari se half of the energy of other bulbs and last up to ten times longer.
9
2004-2005 Annual Report Highlights of fiscal Year 2004-2005 Project ANGEL LI RECYCLING Inside the Home...
By recycling a foot-Ull sack of newspapers, enough energy is aved to take a hot shower every day for a week.
Outside the Home...
During dry periods, cur the gass high and let the clippings turn into mulch to keep the lawn f-om drying out. This
'recycling" of thb gras reduces the amotnt of water needed to keep a lawn green.
LADWP continually does its best to consider the individual needs of all its customers. This year, as part of Project ANGEL (Assist Neighbors by Giving Energy for Living), nearly 2,100 low-income customers received more than
$100,000 (a maximum of $100 to each qualified applicant) in financial assistance for use toward payment of their current unpaid LADWP bill.
Project ANGEL is a charitable funds program in conjunction with United Way, Inc.
whereby customers voluntarily donate extra money when they pay their. utility bill in order to assist other customers who may be experiencing financial'difficulties: Since P983, more than 25,000 families have been assisted through Project'ANGEL.
10
2004-2005 Annual Report Water & Energy Facts in Brief WATER SERVICES Year ended June 30 2005 2004 Use of Water Average Los Angeles population served Average daily use per capita (gallons)
Water sales for fiscal year (billion gallons)
Water Supply (in billions of gallons)
Local supply (groundwater)
Los Angeles Aqueduct (Owens Valley)
Metropolitan Water District (California and Colorado River Aqueducts)
Gross supply Diversion from (to) local storage/transfers Net supply to distribution systems 3,983,875 131.7 191.5 21.6 95.3 82.2 199.1 (0.7) 198.4 3,938,200 139.3 200.8 30.7 73.4 119.8 223.9 1.0 224.9 ENERGY SERVICES Year ended June 30 2005 Number of Customers Residential Commercial Industrial All others Total customers of all classes 1,236,845 182,890 14,107 3,458 1,437,300 2004 1,230,449 180,646 14,664 2,676 1,428,435 Power Use Sales to ultimate customers
- kilowatt (kW" hours Sales to other utilities
- kW hours Average annual kW hours per residential customer Net dependable capacity, kilowatts 23,219,546,752 2,223,725,000 5,711 7,135,000 23,634,252,360 1,367,611,000 5,906 7,144,000 II
2004-2005 Annual Report Watcr Services Selected Financial Data and Statistics Restated Restated Restated Restated
($ Millions) 2005 2004 2003 2002 2001 Statement of Income - Revenue, Expenses, and Changes in Fund Net Assets Operating revenues Residential 218.4 243.3 227.2 225.6 217.0 Multiple Dwelling Units 169.6 176.6 169.8 169.3 167.3 Commercial and industrial 123.3 128.6 129.1 125.7 126.9 Other 49.4 50.8 32.7 35.3 33.7 Uncollectable Accounts (2.4)
(3.0)
(5.8)
(5.5)
(3.9)
Total operating revenues 558.3 596.3 553.0 550.4 541.0 Operating income 97.0 78.2 47.2 89.0 99.9 As % of operating revenues 17.4%
13.1%
8.5%
16.2%
18.5%
Increase in fund net assets 38.4 18.6 4.5 56.9 75.5 Balance Sheet Net utility plant
$ 3,198.8 2,993.0
$ 2,848.9
$ 2,694.9
$ 2,454.7 Capital additions, net 278.0 285.7 245.9 339.8 254.4 Capitalization Fund net assets 1,935.1 1,896.7 1,792.1 1,787.6 1,730.7 Long-term debt 1,395.0 1,212.1 1,297.2 1,000.4 1,011.2 Advance refunding bonds 80.6 Total capitalization 3,330.1 3,108.8 3,089.3 2,788.0 2,822.5 Debt as % of net utility plant (A 43.6%
40.5%
45.5%
37.1%
41.2%
Interest on debt 61.2 51.4 46.5 40.2 46.2 Transfers to City of L.A.
29.8 27.6 27.5 27.2 25.5 Operations Gallons sold (billions) 191.5 200.8 193.3 196.9 196.8 Customers -
average number (thousands) 663.8 661.8 659.1 655.0 649.9 Average revenue per hundred cu. ft. sold (in cents)
Residential 215.0 222.6 219.0 216.9 212.6 Multiple Dwelling Units 209.8 211.7 208.0 204.1 196.2 Commercial and industrial 219.5 224.6 230.6 218.9 218.4 Water supply (billions of gallons)
Local supply 21.6 30.7 29.6 23.9 27.7 DWP Aqueduct 95.3 73.4 66.4 74.4 77.9 Metropolitan Water District 82.2 119.8 121.3 121.3 111.9 Gross supply 199.1 223.9 217.3 219.6 217.5 Diversion from (to) local storage (0.7) 1.0 (0.7) 2.8 (0.9)
Net supply to distribution systems 198.4 224.9 216.6 222.4 216.6 (A) Excludes revenue notes and advance refunding bonds 12
2004-2005 Annual Report Eroergy Services Selected Financial Data and Statistics Restated Restated Restated Restated
($ Millions) 2005 2004 2003 2002 2001 Statement of Revenue, Expenses and Changes in Fund Net Assets Operating revenues Residential 693.6 717.9 643.6 632.1 655.8 Commercial and industrial 1,421.0 1,460.8 1,403.4 1,377.1 1,423.7 Sales for resale 102.4 74.0 64.1 191.1 943.8 Other 48.3 49.7 47.5 46.3 47.3 Uncollectable Accounts (9.6)
(14.3)
(12.7)
(11.6)
(11.9)
Total operating revenues
$ 2,255.7
$ 2,288.1
$ 2,145.9
$ 2,235.0
$ 3,058.7 Operating income 173.4 252.7 222.1 364.1 419.9 As % of operating revenues 7.7%
11.0%
10.3%
16.3%
13.7%
Increase in fund net assets 10.8 50.5 67.7 252.7 313.8 Balance Sheet Net utility plant
$ 5,299.0
$ 5,165.1
$ 4,963.4
$ 4,565.7
$ 4,372.6 Capital additions, net 378.9 547.5 672.9 523.4 453.4 Capitalization Fund net Assets 4,061.7 4,050.9 3,693.1 3,625.3 3,374.0 Long-term debt 3,480.7 3,356.5 3,232.1 3,281.9 3,264.2 Advance refunding bonds 244.5 Total capitalization 7,542.4 7,407.4 6,925.2 6,907.2 6,882.7 Debt as % of net utility plant (A 65.7%
65.0%
65.1%
71.9%
74.7%
Interest on debt 148.3 135.8 141.2 154.6 185.4 Transfers to City of L.A.
160.2 210.2 185.4 179.2 119.8 Operations Kilowatt hours sold (billions) 25.4 25.0 23.7 23.6 26.6 Customers -
average number (thousands) 1,437.3 1,428.4 1,420.8 1,414.4 1,452.2 Average revenue per kWh sold (in cents)
Residential 9.8 9.9 9.8 10.0 9.8 Commercial and industrial 9.0 9.2 9.1 9.0 9.0 Energy production (billions in kWh)
Hydro 1.5 1.6 1.6 1.9 2.1 Thermal 14.8 13.7 12.3 12.7 16.3 Total generation 16.3 15.3 13.9 14.6 18.4 Purchases 12.1 13.3 13.2 12.6 12.0 Total production 28.4 28.6 27.1 27.2 30.4 Net system capability (thousand megawatts)
Hydro 1.6 1.7 1.7 1.8 1.8 Thermal 3.4 3.1 3.2 3.2 3.2 5.0 4.8 4.9 5.0 5.0 Jointly owned and firm purchases 2.1 2.2 2.1 2.0 2.0 Total 7.1 7.0 7.0 7.0 7.0 (A) Excludes revenue notes and advance refunding bonds 13
For additional copies contact:
Public Affairs Room 1536 Post Office Box 51111 Los Angeles, CA 90051-0100 Telephone (213) 367-1361 Printed on recycled paper 14
Los Angeles Department of Water and Power II North Hope Street Los Angeles, CA' 90012
Southern Transmission System Project
-m Mead-Phoenix Transmission Project Mead-Adelanto Transmission Project Palo Verde Nuclear Generating Station Hoover Uprating Project San Juan Generating Station o Magnolia Power Project Member Agencies
Southern California Public Power Authority (SCPPA), a joint powers agency consisting of non-profit, locally owned and governed public power systems comprising eleven municipal utilities and one irrigation district, was formed in 1980 to provide for joint financing, construction and operation of transmission and generation projects. To accomplish its mission, SCPPA is:
- Not-for-profit (public agency)
" Governed locally (locally elected officials)
" Customer owned (no stockholders seeking high profits)
" Vertically integrated (focuses on and remains responsible for power supply, transmission, distribution, and customer service)
" Meeting local mandates of obligation to serve by planning to meet long-term contracts for power through
- Ownership of generation and/or transmission and long-and-short term contracts for power supplies or transmission
" Providing diversity of power supplies, including renewable resources (solar, wind, and electric generation from geothermal, and landfill gas)
" Optimizing its energy resources, and
" Providing aggressive, local demand-side management programs.
SCPPAs members are the municipal utilities of the cities of Anaheim, Azusa, Banning, Burbank, Cerritos, Colton, Glendale, Los Angeles, Pasadena, Riverside, and Vernon, and the Imperial Irrigation District, that together deliver electricity to over 2 million customers over an area of 7,000 square miles, and with a total population exceeding 5 million.
The Authority currently has three generation projects and three transmission projects in operation, generating and bringing power from Arizona, New Mexico, Utah, and Nevada. A fourth generation project, wholly owned by the Authority, is a combined cycle natural gas-fired generating plant with a nominally rated net base capacity of 242 megawatts that began commercial operation in September 2005.
SCPPAs projects have been financed through the issuance of tax-exempt bonds, backed by the combined credit of the SCPPA members participating in each project. As of June 30, 2005, SCPPA has issued $10.1 billion in bonds, notes, and refunding bonds, of which $2.1 billion was outstanding.
In order to support its primary purpose, SCPPA is also involved in legisla-SCPPA will provide tive advocacy, contracting for support services, sharing of information, cost-effective joint administrative services, analyses, training and regulatory monitoring on action services that behalf of its members.-
supplement member programs and activities, and that secure long-term physical supplies at predictable pricing levels for usage in k-
" power generation to MImssure continued member success.
SCPPA provides financing and oversight for large joint projects in the electric utility industry and through coordinated efforts, facili-tates, implements, and communicates information relative to issues and projects of mutual interest to its members as determined by the Board of Directors.
S CPPA OFHCERS & STAFF From left to right: Glenn 0. Steiger, Vice President, Phyllis E. Currie, President, Bill D. Carnahan, Executive Director From left to'right; Geri Mitchell, Office Manager, Manny Robledo, Energy Systems Manager, Richard H elgeson, General Counsel, Salpi Bouboushian, Administrative Analyst, Craig Koehler, Finance and Accounting'Manager, Phyllis Brown, Government Affairs Manager, and Steve Homer, Project Administrator.
2
PRESIDENT 'S uring 2005, the Southern California Public Power Authority (SCPPA) cele-brated 25 years of its member agencies successfully working together as a joint action agency. Backed by one of the strongest financial ratings in the utility industry, SCPPA continues in its traditional role of providing financing for our Members' generation and transmission projects. SCPPA debt refinancings result-ed in over $21 million gross debt service savings during the fiscal year. Today, SCPPA is a participant in three major generation projects and has three transmission projects in operation, bringing generation and power to Southern California from Arizona, Nevada, New Mexico, and Utah. On a combined basis, SCPPAs members currently deliver electricity and services to over 2 million customers covering an area of approximately 7,000 square miles.
Through the collaborative efforts of its members, SCPPA has developed a compre-hensive and dynamic strategic plan that provides a common vision for its members and a platform for joint action. This planning was exemplified during 2005 in SCPPAs commitment to preserving local control, and providing low-cost elec-tricity and reliable service for our customers. The high point of this year's success is SCPPAs Magnolia Power Project (MPP), which began operation in September, 2005. The MPP consists of natural gas-fired combined cycle generation with a nominal rating of 242 megawatts (peak of 310 megawatts), and serves the communities of Anaheim, Burbank, Cerritos, Colton, Glendale, and Pasadena.
The project is located in an urban setting, near downtown Burbank, and the Project Manager, Burbank Water and Power, was extremely successful in gaining local support for the project from the City Council and citizens. The project utilizes existing infrastructure, and is designed to operate solely on reclaimed waste water. MPP is one of the most efficient and environmentally sensitive projects of its kind. In fact, Power Magazine named the Magnolia Power Project its "2005 Plant of the Year", noting Magnolia's high efficiency, low emission, zero liquid discharge and urban setting.
Further testimony to SCPPAs strategic planning, is its investment in natural gas reserves. The long-term economic benefits of this investment to our consumers was highlighted by the devastating effects of hurricane Katrina and the resulting effects it had on the oil and gas industry from increased market volatility. SCPPA also continues its commitment in renew-ables with its latest request for proposals for 75 MW, a message that was well-received by the California State Legislature.
SCPPA has significantly increased its involvement in legislative and regulatory affairs at both the state and federal levels to protect represented customers, by assuring resource adequacy, excellent reliability, and environmental stewardship. At the federal level, SCPPA was involved in voicing its opinion loud and clear on the Energy Policy Act of 2005 (EPAct), which was passed with bi-partisan support in both the House of Representatives and the Senate. During a long debate, SCPPA consistently opposed proposals that would weaken local control or undermine the ability of public power systems to serve their electricity consumers reliably and affordably. SCPPA also fought hard for inclusion of provisions that would enhance the reliability of the bulk power market, provide incentives for consumer-owned utilities roughly equal to those provided for private power companies and protect consumers against market power abuses.
SCPPA also continues to provide effective forums of collaboration through such committees as Customer Service, Transmission and Distribution, Engineering and Operations, Public Benefits programs, Resource Planning and Renewables. These committees not only assist members to produce benchmarking and best practices, but also provide training, joint contracting for services and fuel acquisition for power generation, as well as, acquisition of renewable supplies such as wind, land-fill gas and geothermal.
SCPPAs achievements throughout the year exemplify to policy makers the value of local control, and SCPPAs accom-plishments are a demonstration of genuine leadership in California's electricity industry achieved through the dedication of local elected officials who displayed insight, wisdom and ability to respond to challenges. Working together, SCPPA members are providing and delivering reliable service with competitive and stable rates. SCPPA is responsibly meeting the energy needs of our Members' customers and the communities they serve, and is ready to respond in meeting the new challenges within our industry today and in the years to come.
Phyllis E. Curne President3 3
Er...
-f t all started twenty-five years ago. This year, SCPPA marks its 25th year as a Joint Action Agency. First formed in 1980 by the eleven original members (Anaheim, Azusa, Banning, IBurbank, Colton, Glendale, Los Angeles, Pasadena, Riverside, Vernon and the Imperial Irrigation District), SCPPA came into existence to aid the public power systems in Southern SCalifornia, to provide financing for their participation in electric generating facilities and high voltage transmission lines. Its newest member, Cerritos, joined SCPPA in 2003. Today,
_SCPPAs twelve members deliver electricity and provide services to over 2 million customers covering an area of approximately 7,000 square miles. SCPPA continues in its traditional roles of providing financing for our Members' three major generation projects and three transmission projects in operation, Lgenerating and bringing power from Arizona, New Mexico, Utah and Nevada. It has been rewarding to have been asso-
_ciated with SCPPA for most of its existence and, as its Executive Director, I am very proud to be a part of the expansion and continued success.
SCPPAs investments have traditionally been in the areas of coal, hydroelectric, natural gas-fired generation, and nuclear, as well as high voltage transmission to deliver energy to California. To meet the ever increasing demand for energy, new investments in local base load and peaking natural gas-fired units will help satisfy these needs and increase overall system reliability. Newly planned expansion and re-powering projects through the year 2010 will add approximately 2,000 LMegawatts of new gas-fired generation, and will be built to either replace current third-party power contracts or to retire older less efficient local generating units. SCPPA has been expanding its role in order to meet the challenges facing the electric industry. The most dramatic example of this success is the Magnolia Power Project (MPP), the first wholly-Sowned and operated SCPPA project. MPP is a combined cycled natural gas-fired plant, located in Burbank, California, with Burbank Water and Power acting as the Project manager and operator for SCPPA. The Project began operation in September 2005. MPP generates 242 megawatts to meet base-load capacity and has a peaking capacity in excess of 300 megawatts. Recognized by Platts Power Magazine's highest honor as "2005 Plant of the Year", Magnolia will utilize the latest technology and will meet one of the strictest environmental standards and regulations in the nation.
In addition to the conventional areas of power, investments are also being made to provide customers with more renewable generation and energy efficiency. Renewable energy will continue to play an important role for the future.
Investment by SCPPA members in renewable programs have totaled nearly $70 million over the past five years. With its latest Request for Proposals for 75 megawatts, SCPPA members have an ongoing commitment to renewable energy, sup-porting an aggregate total of 69 existing and planned projects representing 588 megawatts of generating capacity from renewable resources, that include wind, solar, geothermal and biomass. By 2010 on a combined basis, SCPPA members expect to have approximately 28% of their generation portfolios consist of renewable energy. New renewable projects will further diversify generation portfolios, and also benefit the environment by reducing air emissions when compared to conventional generation.
Natural gas fired power generation has historically fulfilled peaking or intermediate demands, however, for economic, environmental and reliability reasons, SCPPA members have recently invested in a significant amount of base-load natu-ral gas generation. While the new units will use less fuel on a per-unit basis, they will require natural gas at stable prices to produce reliable low-cost electricity. To secure firm delivery of natural gas at stable prices in a highly volatile market, SCPPA successfully completed its first phase of planned purchases through the acquisition of natural gas leases in Pinedale, Wyoming and other real property from Anschutz Energy Corporation of Denver, Colorado. The transaction totaled in excess of $300 million for members of the SCPPAs Natural Gas Reserve Project, consisting of six members (LADWP, Anaheim, Glendale, Burbank, Pasadena, Colton) and the Turlock Irrigation District. The transaction, believed to be the largest natural gas field owned by public power utilities, should assure the participants a secure long-term and stable supply of natural gas to fuel their various power plants for many years to come.
It is with a great deal of pride that we reflect on the successes of the first twenty-five years. With the continued vision-ary guidance and willingness to work together of SCPPAs highly successful members, we also look forward with great anticipation to the new challenges. SCPPA and its members know that together we have the ability to provide new and exciting solutions for whatever our industry has to offer.
Bill D. Carnahan Executive Director 4
CELEBRATING 25 YEARS OF n 1980 the Southern California Public Power Authority (SCPPA) was formed by the public power systems, commonly known as municipal electric utilities, in Southern California to provide financ-ing for their participation in electric generating facilities and high voltage transmission lines. The original members of SCPPA, Anaheim, Azusa, Banning, Burbank, Colton, Glendale, Los Angeles, Pasadena, Riverside, Vernon and the Imperial Irrigation District, have been providing electricity and water services to their cities for over 100 years. SCPPAs newest member, Cerritos, joined SCPPA in 2003. Since 1980, SCPPAs members have worked together and presently deliver electricity and pro-vide services to over 2 million customers covering an area of approximately 7,000 square miles. As one of the finest examples of the benefits of local control, when California was in the midst of the great "deregulation experiment", SCPPA members decided to stay the course, continuing their com-mitment to the obligation to serve customers with low rates and reliable service, resulting in their being part of the solution to California's electricity problem.
As stated in its mission, SCPPA provides financing and oversight for large joint projects in the electric utility industry and, through coordinated efforts, it facilitates, implements and communicates informa-tion relative to issues and projects of mutual interest to its members as determined by the Board of Directors. SCPPA currently is a participant in three major generation projects and three transmission projects in operation, generating and bringing power from Arizona, New Mexico, Utah and Nevada.
A fourth generation project, the Magnolia Power Plant located in Burbank, California, is wholly owned by SCPPA, and began operation in September, 2005. In addition, planned expansion and re-powering of generating capacity through the year 2010 will add approximately 2,000 MW of new gas-fired generation, built to either replace current power contracts or to retire-older less efficient units. With a goal of 20% retail sales procured from renewables by 2017, SCPPA members' commit-ment to renewable energy predates legislative activity, supporting an aggregate total of more than 60 existing and planned projects representing 588 MW of generating capacity at a cost of nearly
$70 million over the last five years from renewable resources, including wind, solar, geothermal and biomass. By the year 2010 on a combined basis, SCPPA members expect to have 28% of their genera-tion portfolios consist of renewable energy.
To further demonstrate its ability to respond to current market conditions, the SCPPA Board of Directors approved the Natural Gas Acquisition Project. In realizing one of their goals in acquiring natural gas reserves for their own generating facilities, several SCPPA members, including LADWP, the cities of Anaheim, Burbank, Colton, Glendale, and Pasadena, in addition to Turlock Irrigation District, successfully completed an acquisition of natural gas reserves and other real property in Pinedale, Wyoming. SCPPA financed approximately $26 million on behalf of three of its members, Anaheim, Burbank, and Colton. The other participants in the proj-ect, LADWP, Glendale, Pasadena, and the Turlock Irrigation District, completed the financing of this project totaling in excess of $300 million. Gas began to flow to the participants at 12:01 a.m. on July 1, 2005. This is a unique project and is believed to be the largest natural gas field owned by public power utilities and should assure the participants a secure long-term and stable supply of natural gas to fuel the various power plants.
This silver anniversary highlights the importance and contributions to the state's economic vitality and stability in the face of challenges in the electricity industry by the member cities of the Southern California Public Power Authority, for their steady and visionary leadership they have exemplified over the last 25 years.
With its distinguished ability to face challenges and change with creative response, SCPPA and its members look forward to the next 25 years, guided by the wisdom of local control, commitment to the obligation to serve customers, and to reliably provide electricity during turbulent times in the electricity industry.
m) 5
OPERAt INS
/
//
he steam generators in Unit 2 were successfully replaced during the fall of 2003. At fiscal 2004 year-end, the plant was poised to replace the steam gen-erators in Unit 1, with Unit 3 to follow in 2007.
PRODUCTION COST (Operation and Maintenance plus Nuclear Fuel)
Calendar Year Cents per kWh 1993 2.02 1994 1.93 1995 1.61 1996 1.45 1997 1.33 1998 1.28 1999 1.25 2000 1.25 2001 1.27 2002 1.28 2003 1.32 2004 1.45 1 6 Burbank/Glendale/Pasadena Percentage of (4.4% each)
SCPPA member Azusa/Banning/Colton
]
participation in (1% each)
Vernon
~Palo Verde Project Imperial Irrigation District --
Riverside-Los Angeles -
I I
I I
I 5 0%
10% 20%
30% 40%
50%
60%
2004-2005 OPERATIONS Generation Capacity (Millions of Utilization MWHs)
(%)
Unit I Unit 2 Unit 3 Aggregate 10.2 9.7 7.8 27.7 93.3%
83.5%
71.4%
82.7%
6
ive SCPPA participants own 41.8%
Ioof Unit 3 at the San Juan Generating Station, a coal-fired plant in New Mexico. A series of.
Interim Invoicing Agreements for fuel has led to high capacity factors and lower per unit fuel costs.
The underground mine is performing well, and the plant is embarking on a major environmental upgrade project. Unit 3's major work is scheduled for the spring of 2008.
GIn&,k -
Banning -
C.lton -
A-.us-
[nIn perial Irrigation -
I Dis rict Percentage of SCPPA member M-participation in San Juan Project 0% 10% 20% 30% 40% 50% 60% 70%
canl kl-wmý UýNlI 3 O, PERAMIONS 7
Pasadena -
Glendale -
Burbank -
Azusa/Banning/Colton (I % each)
Rierside Anaheim -
Los Angeles -
Percentage of SCPPA member participation in Mead-Phoenix Project I
I I
I I
I I
0%
10% 20% 30% 40% 50% 60% 70%
F-
~~~1 LLJ LJJ
=
he two 500-kV transmis-sion lines, which connect
.T Phoenix to Las Vegas, and Las Vegas to Southern California, completed their eighth year of dependable operation for the nine SCPPA members who participate in the projects.
Pasadena -
Glendale -
Burbank -
Colton -
Banning -
Azusa -
AnaheinMRieerside (13.5% eah)
Los Angeles -
3 Percentage of SCPPA member participation in Mead-Adelanto Project I
I I 30 I
I4 I 0% 10% 20% 30% 40% 50% *60% 70%
I.
LJJ PHOJECTS ANS SSII 8
0D Burak --
Percentage of SCPPA member Colton participation in Banning-Hoover Azusa --
Uprating Project Riversde-M_
I I
I I
I I
I 0%
10% 20%
30% 40% 50% 60% 70%
he Hoover Uprating Project contin-ues to provide six SCPPA members with low-cost, renewable energy (hydro). A SCPPA representative is active in the development of the Lower Colorado River Multi-Species Conservation Program.
"--=
C=
C-.
9
STS s usual, the STS operated A
with near-perfect avail-ability (98.91%), deliver-ing over 14 million MWHs to the six SCPPA members who are par-ticipants. The power comes 488 miles from the Intermountain Power Project, in Utah, over the
=+/-500-kv DC line.
r7=
Pasadena -
M Percentage of SCPPA member Glendale --
participation in Burn,,k -
Southern Transmission Riveride -
System Project Anaheimn -
los Angeles --
0- 10 I2 I 4
I I 0%
10% 20% 30% 40% 50% 60% 701%
10
U, RESERVES PROJECT CPPA negotiated its first purchase
<of gas in the ground, with the t))4 deal closing July 1, 2005. SCPPA Members Los Angeles, Anaheim, Burbank, Colton, Glendale, and Pasadena joined together with the Turlock Irrigation District to purchase shares of existing natural gas wells in Wyoming. This pur-chase, along with similar future purchases, will provide a secure source of gas for the participants, and hedge against volatile prices in the market.
if;-"
I mwv Percentage of
\\
t the end of the fiscal year, construction was nearing completion on the Magnolia Power Project, a 242 megawatt natural gas-fired, combined cycle plant, located on the site of an existing plant in the City of Burbank. It' replaces an older, less-efficient, unit. The result will be more power from less fuel, with less pollution.
The plant reached commercial operation in September, 2005, and is the first project to be wholly-owned and operated by SCPPA members.
The Participants are. Anaheim, Burbank, Cerritos, Colton, Glendale, and Pasadena..",,`
Pasadena -
Glendale -
Burbank -
Colon -
Anaheim -
Cerritos -
SCPPA member participation in Magnolia Power Project I 0 I
20%
I30%
,I 5
6,I 0%, 10% 20% 30% 40% 50% 60% 70%
j 1<
27 I-7
\\L
\\
/
e-C=
11
ACiTIV II IS DERIVNrIVE INSTRLIMENIS STS Fixed Spread Basis Swap - In connection with the Southern Transmission Project, the Authority entered into a $100 million 18.5-year BMA versus LIBOR floating-to-fixed rate basis swap in November 2004. Under the basis swap, SCPPA will pay a variable rate equal to the BMA index, and in exchange will receive 65% of LIBOR plus a fixed margin or spread of 66.4 basis points (bps). Public Financial Management (PFM) negotiated the structure, terms and pricing of the swap directly with the counterparty, J.P. Morgan Chase Bank, N.A.
The basis swap produces net positive cash flow for SCPPA given the expected positive difference between the floating rate received (65%
of 1-month LIBOR + 66.4 bps) and the floating rate paid (BMA index).
The fixed margin of 66.4 basis points represents the fair Market or breakeven spread differential prevailing at the time of trade execution. Based on PFM's recom-mendation, the financing team also moved quickly to capture particularly favorable market conditions that resulted in an additional $550,000 savings. The transaction generated $8.24 million in expected present value savings, or 8.24%.
LoNC; TEM DEBT San Juan Power Project Revenue Bonds, 2005 Refunding Series A (San Juan Unit 3) - In April 2005, SCPPA issued $71,880,000 San Juan Power Project Revenue Bonds, 2005 Refunding Series A (San Juan Unit 3). The 2005 bonds were issued to provide moneys to refund all of the Authority's San Juan Power Project Revenue Bonds, 2002 Refunding Series B (San Juan Unit 3) and pay costs of issuance relating to the 2005 Bonds. UBS Financial Services, Inc. was appointed to serve as sen-ior manager and book runner of the bonds due to their in-depth knowledge and familiarity with the San Juan Power Project Revenue Bonds. The 5.00% fixed-rate revenue bonds, were insured by Financial Security Assurance, Inc. and have underlying credit ratings of A2 and A+ by Moody's Investors Service and Standard and Poor's, respectfully. The 2005 Bonds maturing on January I in each of the years 2016 through 2020, are subject to redemption prior to maturity at the option of the Authority on or afterJanuary 1, 2015, in whole or in part at any time at par plus accrued interest.
REiDEMI*IYON Multiple Project Revenue Bonds - On January 4, 1990, SCPPA issued its Multiple Project Revenue Bonds, 1989 Series. Most of the proceeds of the Bonds were used to fund Authority projects, namely the Mead-Adelanto Transmission Project and the Mead-Phoenix Transmission Project. The outstanding Bonds consist of Bonds that are subject to optional redemption at par (the "Callable Bonds") and Bonds that are not subject to optional redemption. The Callable Bonds comprise most of the Bonds currently outstanding. At a meeting held on April 4, 2005, the Authority's Finance Committee determined that it was in the best interest of the Authority to use most of the remain-12
ing available proceeds of the Bonds to redeem all of the Callable Bonds. The Authority's Finance Committee also determined at the April 4 meeting that, subject to the Board's approval, the Callable Bonds should be redeemed and that the redemption should occur on July 1, 2005. In May 2005, the Authority's Board of Directors approved the redemption of $162.1 million Multiple Project Revenue Bonds, 1989 Series, represent-ing all of the callable bonds. The remaining $50.2 million non callable Multiple Project Revenue Bonds will mature July 1, 2010 through July 1, 2013, of which principal and interest will be paid from moneys on deposit in the Investment Agreement with PNC Bank.
OTH-EhR REFUNDINGS AN) TRANSACT1ONS SCPPAs Finance Committee continues to look for opportunities to lower financing costs through, for exam-ple, bond refundings and interest rate swaps. At fiscal year-end, refundings and / or interest rate swaps for the Magnolia Power Project Series A bonds were under consideration.
SCPPA CPPA with all the state's municipal electric utilities experienced an unusual year, with the new 2005-06 legislative session. While usual legislative challenges to local control were encoun-tered, there appears to be an increasing recognition by elected state legislators and officials of the benefits of responsible investment decision-making by local elected officials. SCPPAs leadership role in making solid investment decisions with positive results also encourages state policy. An example is Assembly Bill 380 (AB 380), Assembly Speaker Fabian Nunez' bill, requiring load serving entities to meet peak demand as well as the planning and operating reserves within the planning reserve and reliability criteria of the Western Electricity Coordinating Council (WECC). AB 380 represents an important element establishing stability in California's electricity market. The state's municipal electric utilities are required to maintain generating capacity to meet load requirements, including peak demand and planning and operating reserves; most SCPPA members currently meet or exceed that requirement. AB 380 was signed by the Governor on September 29th, 2005. Seeking to avoid future forecasting clashes over municipal departing load (similar to those following the elec-tricity crisis), Assembly Bill 1723 (AB 1723) provides that both investor-owned utilities and munici-pal utilities must file demand forecasts with the California Energy Commission (CEC). The CEC then evaluates the amount of electricity lost or added by retail providers. While CEC's evaluation is non-binding on the California Public Utilities Commission (CPUC), AB 1723 is intended to assure information is available to determine who is responsible to meet future load. AB 1723 was signed by the Governor on October 7th.
13
U-LEI ISIAT VE REPORT (continued Another of the Speaker's bills, Assembly Bill 1576 (AB 1576), signed by the Governor on September 29th, establishes policy for investor-owned utilities. AB 1576 encourages repowering and replacing aging generation facilities, similar to SCPPAs Magnolia Power Project. The policy, with goals of increased efficiency, reduced air emissions, water use and discharge, and assures recovery of costs by regulated utilities or non-utility generators. This year's renewables portfolio standard (RPS) bill is Senate Bill 107 (SB 107). SB 107 seeks to accelerate meeting the RPS 20% requirement from 2017 to 2010. The bill requires municipal utilities to annually prepare a report for the CEC on the mix of eligible renewable resources used in their portfolios as well as their progress toward meeting the RPS goal. However, SB 107 faced numerous challenges on its way to the governor's desk, including excusing an IOU's RPS obligation if transmission is insufficient to assure delivery of electricity from renewables. SB 107 awaits action on the Assembly floor when the legislature returns to session in January 2006. Much attention was paid to the keystone of Governor Schwarzenegger's electricity policy, Senate Bill I (SBI), during this second year of his term. The goal is to add to California's electricity supply 3,000 MW by 2018. The Governor's proposal envisions installation of photo-voltaic panels on one million new and existing residential and commercial buildings thereby avoid-ing putting "steel in the ground". Because the bill's silence on cost to consumers raised concerns, SCPPA, with California Municipal Utilities Association (CMUA) members, sought and achieved an amendment to the bill. The amendment assures local control over investment decisions thereby allowing a local governing body to adopt, implement and finance its own solar roofs program. The amendment also provides a fair-share cap on the state's municipal utilities portion of the state-wide investment. The bill stalled in the Assembly Utilities and Commerce Committee over labor issues, prompting Republicans to pull their support for the bill. With November's defeat of all ballot measures backed by the Governor, whether SB I's differ-ences can be resolved during 2006 makes the fate of this bill unclear.
SCPPA and its members proudly support all our troops, especially those in Iraq and Afghanistan, by putting their commitment into action and sup-porting Assembly Bill 1666 (AB 1666). Known as the California Military Families Financial Relief Act of 2005, AB 1666 provides peace of mind to mili-tary families by protecting their utilities from shutoff. The protection extends to electricity, natural gas, water, sewer, solid waste collection and telephone. When a reduction in household income results from a member of the household being called to active duty status in the military, a qualified customer, upon application, will receive 180 days of shutoff protection, which may be extended until the service member is released from active duty. The Governor signed AB 1666, authored by Assemblymember Dario Frommer, on September 22nd.
On the federal level, President Bush signed into law the Energy Policy Act of 2005 (EPAct)in August, 2005, which was passed with bi-partisan support in both the House of Representatives and the Senate. Passage of the comprehensive bill was the culmination of a decade-long Congressional effort. It began with federal legislation to deregulate the electric utility industry but grew into a 14
more comprehensive federal energy policy platform. During that long debate, SCPPA consistently opposed proposals that would weaken local control or undermine the ability of public power systems to serve their electricity consumers reliably and affordably. SCPPA also fought for inclusion of provisions that would enhance the reliability of the bulk power market, provide incentives for consumer-owned utilities roughly equal to those provided for private power companies and protect consumers against market power abuses.
" Largely, SCPPA believes that the electricity title in EPAct is consistent with its goals, and its implementa-tion will allow SCPPA member utilities to continue their strong tradition of reliable, affordable electric service.
" EPAct authorizes creation of a new Electric Reliability Organization that will issue and enforce mandatory reliability standards for all participants in the North American bulk power market.
The native load provisions of the new law protect the existing physical transmission rights of California load serving entities against forced conversion to financial or tradable rights, unless a utility voluntarily joins the California Independent System Operator. The native load section also directs the Federal Energy Regulatory Commission (FERC) to ensure that all load-serving entities are able to obtain long-term transmission rights to deliver long-term power supplies. These transmission protections will help ensure that SCPPA members will have reasonable certainty about the delivered cost of power to customers. SCPPA also favors Congress' decision not to mandate participation in Regional Transmission Organizations or Independent System Operators. EPAct also authorizes several renewable energy incentives for consumer-owned utilities. The new Clean Renewable Energy Bond (CREB), modeled on the Q-ZAB bond used for school construction, authoriz-es issuance of $800 million in bonds to construct renewable energy projects over two years, with bond pur-chasers receiving a federal tax credit instead of interest paid by the issuer. The CREB program is intended to provide rough parity with the Production Tax Credit (PTC) for renewable project available to investor-owned utilities, because it does not require federal appropriations. SCPPA members can also apply to receive post-production incentive payments for electricity generated from qualified renewable projects via the Renewable Energy Production Incentive (REPI) program, which EPAct reauthorized for ten years. The REPI reauthorization also provides that, in years of a funding short-fall, 40% of appropriated funds must go to "Tier 2" technologies, which include landfill gas. Further, SCPPA members may benefit from extension of the Production Tax Credit for private developers of renewable projects, if they contract to purchase energy from such facilities under share-the-benefits contracts. All three renewable incentive programs may help SCPPA members meet their renewable portfolio targets in a timely fashion. Congress' decision not to mandate a federal Renewable Portfolio Standard in EPAct is also viewed as a "win" by SCPPA.
On the consumer protection front, EPAct grants FERC broad new authority to protect electricity markets and consumers from market manipulation. The market manipulation language is modeled on similar authority granted to the Securities and Exchange Commission, to protect against fraud and wrong-doing in the securi-ties markets. EPAct also grants FERC broader authority to review utility mergers and asset transfers, includ-ing transfers of stand-alone generation facilities previously not subject to Commission review. Unfortunately these new consumer protections were added to EPAct to attempt to mitigate the repeal of the Public Utility Holding Company Act (PUHCA) also contained in the new law. SCPPA and numerous other consumer 15
IGPNACtO R. TRONCOSO Director of Utilities Glendale Water and Power C.'viY F
w: ANA] EIM Anaheim Public Utilities is the only municipal water and electric utility in Orange County. We have provided our residential and business customers with water and electric services since 1895. Our residential and com-mercial electric rates are among the lowest in Orange County, and we maintain our tradition of delivering quality water at a competitive price. The annual electric bill for Anaheim customers is significantly lower than neighboring cities. With a focus on serving Anaheim-specific needs, we offer a value-packed array of Advantage Services - helping our business customers make more efficient and economical use of the critical resources we provide. Businesses have dozens of Advantage Services from which to choose, including rebates, incentives and retrofits to help them save water and energy, and reduce their utility bills. Anaheim Public Utilities will continue to work to the best advan-tage of Anaheim consumers. With a strong, creative management team, sound resources and financial planning, and a cadre of experienced and dedicated employees, we will maintain sharp focus on meeting the community's long-term power needs and offer other measures that will help our customers make efficient use of electricity.
IMPERIAL IRRIGrAION DISTRICT lID entered the power industry in 1936 and today serves 126,000 customers with a peak load of 910 MW with 1,100 MW of generating resources. Among lID-owned resources are 24 MW of low head hydro units along the All American Canal, 307 MW of gas-fired steam and combined cycle units, and 162 MW of peaking gas tur-bines. In addition to lID's share of SCPPA resources comprising 104 MW at San Juan and 14 MW at Palo Verde, lID has 200 MW of geothermal, renewable 16 resources under long-term purchase contracts.
GLtENN 0. STI FGE.R
- Manager, Energy Department Imperial Irrigation fl Districti i
(I:IY or AZUSA The City's electric utility was established in 1898 after the City purchased a private power company. The fore-sight and planning of those early pioneers continues to be the cornerstone of Azusa Light & Water today. It is the mission of Azusa Light & Water to provide reliable and cost effective electric and water utilities to the citizens and businesses within its service area. Azusa Light & Water continues to be proactive in promoting energy and water conservation programs to its cus-tomers, and to its future customers by continual funding of a resource conservation education programs with the local school district.
C(4y or" GiENDI)AlE Incorporated in 1906, Glendale purchased its electric utility in 1909, obtaining power from outside suppliers.
In 1937, it began receiving power from the Hoover Dam and inaugurated the first unit of its own steam generat-ing plant units with 250MW of gas-fired steam and combustion generating capacity. Glendale Water &
Power (GWP) has a diversified portfolio that also includes coal, nuclear, and hydro generating resources, as well as a comprehensive renewables resource pro-gram in landfill gas, wind, and geothermal projects.
Today, GWP provides reliable electric services to over 80,000 residential, commercial and industrial customers within a 32 square mile area. Known for excellence in customer services, GWP's cutting edge Smart Business Energy Saving Upgrade program earned the CMUA 2004 Community Efficiency Award for the best usage of public benefit funds. GWP continues to invest in improving the system infrastructure to ensure its long-term reliability.
RONALD 0. VAZ)UEZ Chief Financial Officer Los Angeles Department of Water and Power CI 0:Y OF BANNING The City of Banning Electric Utility provides electric service to more than 11,800 metered accounts covering an area of over 25 square miles. Established in 1913, Banning's energy resource base includes portions of coal, nuclear and hydro generating plants, which provide the majority of electricity required to meet its summer peak demand of 48 MW. The City supports clean ener-gy and is committed to adding additional renewable energy resources to its already diverse portfolio. The Utility is dedicated to continue providing quality service to its customers in a safe and reliable manner, at reasonable rates.
LOS ANG-LES DEI.PARTME;NT OFl i
WAIER AND POWER Providing service for more than a century, the Los Angeles Department of Water and Power began deliv-ering water to the city in 1902, and with the water came power. In 1916, LADWP first delivered electicity to the city purchased from the Pasadena Municipal Plant.
A year later, LADWP began generating its own hydro-electric power at the San Francisquito Power Plant No. 1. After purchasing the remaining distribution system of Southern California Edison within the city limits in 1922, LADWP became the sole water and electricity provider for the City of Los Angeles. It is now the largest municipally owned electric utility in the nation, serving a population of 3.8 million residents over a 465 square mile area. LADWP remains on firm financial footing and serves as a valuable asset to the City of Los Angeles.
CITY OF: BURBANK Burbank Water and Power {BWP) began serving both water and electric customers in 1913 and installing on-site power generation in the 1940s. Today it oper-ates about 182 MW of gas-fired capacity and holds 100 MW of jointly owned coal, nuclear and hydro capacity.
BWP is the project manager and operating agent for the Magnolia Power Project (MPP). MPP has a nominal capacity of 242 MW and a peaking capacity of 310 MW.
BWP will receive 31 percent of the power from MPP Other SCPPA participants include: Anaheim, Cerritos, Colton, Glendale, and Pasadena.
CITY OF PASADENA Pasadena Water and Power (PWP) began providing electricity in 1906 and began delivering water in 1912.
The city built its first electric generating steam plant in 1907 and took over operation of its municipal street lighting from Edison Electric. In 1909, Pasadena began the extension of its operations to commercial and resi-dential customers that resulted in the replacement of all Edison Electric service in the city by 1920. While a lot has changed over the years, PWP's strong connection to its customer/owner base remains constant. Today, PWP provides electric service to more than 61,000 metered accounts over a 23 square-mile service area at compet-itive rates. PWP's success is a result of its commitment to remain a valued community asset, an exceptional employer, and a partner in Pasadena's prosperous future.
C""y o F CIRRITZros The first new member to join Southern California Public Power Authority in over 20 years, the City of Cerritos is preparing to serve the electricity demands of its residential and business communities. To further these efforts, Cerritos is participating in the development of the Magnolia Power Project. With the goal of providing a stable and affordable supply of electricity, Cerritos intends on developing a diverse portfolio of power to be delivered as competitively and economically as possible.
CITY OF RIVERSIDE The City of Riverside Public Utilities provides electric service to more than 103,500 metered accounts, representing a service area population of over 285,000.
The utility is committed to the highest quality water and electric services at the lowest possible rates to benefit the community. To maintain their commitment, Riverside has positioned itself well in the electric mar-ket by utilizing short, mid, and long term contracts from power suppliers, and by building power generation sources within its own power grid, including a 40 MW power plant in 2002 and the construction of a 99.6 MW power plant scheduled for operation in early 2006.
Riverside's portfolio includes 27 MW of renewable resources which includes 500 kW of photovoltaic sys-tems within the city.
C.FY OF COUTON Colton Electric Utility was established in 1895 and has provided our customers with reliable and affordable electric service for over one hundred years. Today, Colton is the only publicly owned electric utility in San Bernardino County. We currently serve a peak load of 86 MW with our own generating unit, Agua Mansa Power Plant, and shares of SCPPA's resources at San Juan, Palo Verde, and Hoover Dam. In addition, Colton has invested in renewable resources such as wind, solar, and landfill gas. Our group of dedicated employees remain committed to providing our community superior customer service and reliable electric service while planning for the future power needs of Colton.
CITY OF VIEtRNON Vernon's Utilities Department began serving industrial customers in 1933, with completion of its diesel gener-ating plant. In addition to its own power from diesel units and gas turbines, Vernon also receives power from Palo Verde, Hoover, and various suppliers. Vernon recently completed (October 2005) the construction of its Malburg Generating Station, a gas-fired combined cycle power plant with a net generating capacity of 134 MW. The Malburg Generating Station resides within the city limits. Vernon is part the California Independent System Operator (CAISO) Control Area and is a Participating Transmission Owner.
17
U LEGILATIVE REPOHT (cotinue interests fought for years against repeal of PUHCA, believing that its repeal will lead to more utility mergers, greater concentration of market power and reduced protection for utility consumers and investors. EPAct gives FERC new authority over transmission facilities owned by consumer-owned utilities and over certain wholesale power sales. The so-called "FERC-Lite" provision will require consumer-owned utilities to provide transmission services to third parties at rates and under terms and conditions comparable to those they apply to their own service. SCPPA opposed earlier ver-sions of the "FERC Lite" provision as too expansive. SCPPA supports the "comparability" standard of Order 888, however, and is pleased that the final legislation narrowed FERC's authority in this area. The new refund authority allows FERC to order refunds of certain wholesale power sales into organized markets, if those sales violate market rules or tariffs in effect at the time of the sales.
Despite the fact that the refund provision is narrowly drawn, SCPPA views it as an intrusion into local decision-making. The precise scope of both the "FERC-Lite provision and the refund provi-sion will be determined through FERC rulemakings.
In conclusion, SCPPA is fortunate and appreciative that Congress took legislative steps to improve system reliability, long term transmission rights, provide incentives unique to public power, and to promote the use of renewable energy without imposing heavy-handed and punitive requirements.
For the remainder of the 109th Congress and beyond, SCPPA will continue to be an effective advo-cate by ensuring the continued success of existing programs and policies that support SCPPAs mis-sion of providing low-cost, reliable power to its members.
18
SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY COMBINED FINANCIAL STATEMENTS INDEX Pages Management's Discussion and Analysis.............
20-39 Report and Combined Financial Statements:
Report of Independent Auditors..................
41 Combined Financial Statements..................
42-47 Notes to Combined Financial Statements.............
48-58 Supplemental Financial Information:
Supplemental Schedule of Receipts and Disbursements in Funds Required by the Bond Indenture for the Year Ended June 30, 2005:
Palo Verde Project.........
. 60 Southern Transmission Project..........
. 61 Hoover Uprating Project
. 62 M ead-Phoenix Project......................
63 M ead-Adelanto Project......................
64 M ultiple Project Fund..........
65 San Juan Project..
66 M agnolia Power Project.....................
67 19
SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY MANAGEMENT'S DISCUSSION AND ANALYSIS JUNE 30, 2005 The following discussion and analysis of the financial performance of each of the projects in which the Southern California Public Power Authority (the "Authority" or "SCPPA") has interests, provides an overview of the projects' financial activities for the fiscal year ended June 30, 2005. Descriptions and other details pertaining to the projects are included in the Notes to Combined Financial Statements. Please read this discussion and analysis in conjunc-tion with the Authority's Combined Financial Statements, which begin on page 42.
The Authority is ajoint powers authority whose primary purpose has been to provide joint financing for its member agencies that consist of eleven munic-ipal electric utilities and one irrigation district in California. On a combined basis, these entities provide electricity to more than 2 million retail electric customers. A Board of Directors (the "Board") governs the Authority, which consists of one representative from each member agency.
The Authority has interests in the following projects:
Palo Verde Project - On August 14, 1981, the Authority purchased a 5.91% interest in the Palo Verde Nuclear Generating Station ("PVNGS"), a 3,810 megawatt nuclear-fueled generating station near Phoenix,Arizona, a 5.56% ownership interest in the Arizona Nuclear Power Project HighVoltage Switchyard, and a 6.55% share of the right to use certain portions of the Arizona Nuclear Power ProjectValleyTransmission System (collectively, the "PaloVerde Project").
Units 1,2 and 3 of the Palo Verde Project began commercial operations in January 1986, September 1986, and January 1988, respectively.
Southern Transmission System Project - On May 1, 1983, the Authority entered into an agreement with the Intermountain Power Agency ("IPA") to defray all the costs of acquisition and construction of the Southern Transmission System Project ("STS"), which provides for the transmission of energy from the Intermountain Generating Station in Utah to Southern California. STS commenced commercial operations in July 1986. The Department of Water and Power of the City of Los Angeles ("LADWP"), a member of the Authority, serves as project manager and operating agent of the Intermountain Power Project ("IPP").
Hoover Uprating Project - As of March 1, 1986, the Authority and six participants entered into an agreement pursuant to which each participant assigned its entitlement to capacity and associated firm energy to the Authority in return for the Authority's agreement to make advance payments to the United States Bureau of Reclamation ("USBRK") on behalf of such participants. The Authority has an 18.68% interest in the contingent capacity of the Hoover Uprating Project ("HU").
Mead-Phoenix and Mead-Adelanto Projects - As ofAugust 4, 1992, the Authority entered into an agreement to acquire an interest in the Mead-Phoenix Project ("Mead-Phoenix"), a transmission line extending between the Westwing substation in Arizona and the Marketplace substation in Nevada. The agreement provides the Authority with an 18.31% interest in the Westwing-Mead project component, a 17.76% interest in the Mead Substation project component and a 22.41% interest in the Mead-Marketplace project component.
As.of August 4, 1992, the Authority also entered into an agreement to acquire a 67.92% interest in the Mead-Adelanto Project ("Mead-Adelanto"), a transmission line extending between the Adelanto substation in Southern California and the Marketplace substation in Nevada. Funding for these pro-jects was provided by a transfer of funds from the Multiple Project Fund and commercial operations commenced in April 1996. LADWP serves as the operations manager of Mead-Adelanto.
Multiple Project Fund - During fiscal year 1990, the Authority issued Multiple Project Revenue Bonds for net proceeds of approximately $600 million to provide funds to finance costs of construction and acquisition of ownership interests or capacity rights in one or more, then unspecified, projects for the generation or transmission of electric energy. Certain of these funds were used to finance the Authority's interests in Mead-Phoenix and Mead-Adelanto.
San Juan Project - Effective July 1, 1993, the Authority purchased a 41.80% interest in Unit 3 and related common facilities of the San Juan Generating Station ("SJGS") from Century Power Corporation. Unit 3, a 497-megawatt unit, is one unit of the four-unit coal-fired power generating station in New Mexico.
Magnolia Power Project ("The Project") - In March 2003, the Authority received approval from the California Energy Commission for construction of the Magnolia Power Project. The Project consists of a combined cycle natural gas-fired generating plant with a nominally rated net base capacity of 242 megawatts and was built on a site in the City of Burbank, California.The plant is the first that is wholly owned by the Authority and entitlements to 100%
of the capacity and energy of the Project have been sold to six of its members. The City of Burbank, a Project participant is managing its construction and operation. The major construction activities on the Project are complete and dedication ceremony was held on June 2, 2005. This unit began com-mercial operation in September 2005.
20
SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY MANAGEMENT'S DISCUSSION AND ANALYSIS JUNE 30, 2005 Projects' Stabilization Fund - In fiscal year 1997, the Authority authorized the creation of a Projects' Stabilization Fund. Deposits may be made into the fund from budget under-runs, after authorization of individual participants, and by direct contributions from the participants. Participants have discretion over the use of their deposits. This fund is not a project-related fund; therefore, it is not governed by any project Indenture ofTrust.
The members participate in the Projects' Stabilization Fund by making deposits to the find at their discretion.
Participant Ownership Interests - The Authority's participants may elect to participate in the projects. As ofJune 30, 2005, the members have the fol-lowing participation percentages in the Authority's operating projects:
Magnolia Palo Hoover Mead-Mead-San Power Participants Verde STS Uprating Phoenix Adelanto Juan Project City of Los Angeles 67.0%
59.5%
24.8%
35.7%
City of Anaheim 17.6%
42.6%
24.2%
13.5%
38.0%
City of Riverside 5.4%
10.2%
31.9%
4.0%
13.5%
Imperial Irrigation District 6.5%
51.0%
City of Vernon 4.9%
City of Azusa 1.0%
4.2%
1.0%
2.2%
14.7%
City of Banning 1.0%
2.1%
1.0%
1.3%
9.8%
City of Colton 1.0%
3.2%
1.0%
2.6%
14.7%
4.2%
City of Burbank 4.4%
4.5%
16.0%
15.4%
11.5%
31.0%
City of Glendale 4.4%
2.3%
14.8%
11.1%
9.8%
16.5%
City of Cerritos 4.2%
City of Pasadena 4.4%
5.9%
13.8%
- 8.6%
6.1%
100.0%
100.0%
100.0%
100.0%
100.0%
100.0%
100.0%
The Authority has entered into power sales and transmission service agreements with the above project participants. Under the terms of the contracts, the participants are entitled to power output or transmission service, as applicable. The participants are obligated to make payments on a "take or pay" basis for their proportionate share of operating and maintenance expenses and debt service. The contracts cannot be terminated or amended in any man-ner that will impair or adversely affect the rights of the bondholders as long as any bonds issued by the specific project remain outstanding.
The contracts expire as follows:
Palo Verde Project.......................... 2030 Southern Transmission System Project................
2027 Hoover Uprating Project........................
2018 M ead-Phoenix Project........................
2030 Mead-Adelanto Project..........................
2030 San Juan Project............................
2030 Magnolia Power Project.......................
2036 21
SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY MANAGEMENT'S DISCUSSION AND ANALYSIS JUNE 30, 2005 Critical Accounting Policies Net Assets -
The Authority's billing amounts to the participants are determined by its Board of Directors and are subject to review and approval by the participants. Billings to participants are designed to recover "costs" as defined by the power sales and transmission service agreements. The billings are structured to systematically provide for debt service requirements, operating funds and reserves in accordance with these agreements. The accumulated difference between billings and the Authority's expenses calculated in accordance with generally accepted accounting principles are presented as net assets (deficit). It is intended that this difference will be recovered in the future through billings for repayment of principal on the related bonds.
Investment Policy and Controls -
The Authority's investment function operates within a legal framework established by Sections 6509.5 and 53600 et. seq. of the California Government Code, Indentures of Trust, instruments governing financial arrangements entered into by the Authority to finance and operate Projects, and the Authority's Investment Policy. The Indentures ofTrust authorize the establishment of specific Project funds and accounts, specify how monies are to be applied, and name third party Trustees.
Funds available for investment include proceeds from bonds and notes sales, payments from the participants, maturities of previous investments, earnings, exchanges of securities and interest from swap agreements. Funds are managed and invested separately and principal and earnings are credited and allo-cated to designated funds or accounts as outlined in each Project's Indenture of Trust, or in the Projects' Stabilization Fund which was established by a Board Resolution.
The three fundamental criteria in the investment program, ranked in accordance of importance, are: safety of principal, liquidity and return. An excep-tion to the preceding criteria is made for the Palo Verde Nuclear Decommissioning Trust Funds, as liquidity will not be a factor until 2023. The invest-ment criteria for the Decommissioning Trust Funds, in order of importance, are as follows: safety, return, and liquidity.
Debt Management Program -
The Authority's financing goal is to obtain the lowest prudent rates of interest on debt issues and to issue debt in the most cost-effective manner. In addition, the Authority will continue to utilize debt management strategies that reduce the overall cost of borrowing for its members. In general, the Authority issues new money debt and refunding debt on either a negotiated or competitive basis as determined by the Board.
A minimum net present value savings of 5%, as a percent of the refunded par amount, is the general target when determining the potential to refund exist-ing Authority debt.The Authority may also use interest rate swaps or other derivative products to help meet important financial objectives. As ofJune 30, 2005, SCPPA swaps (excluding the 1991 swap) have an expected present value savings of $58.5 million or 10.27%. The expected gross savings is $90.6 million.
Jointly Owned Utility Plant -
The Authority owns interests in several generating stations and transmission systems for which each participant has provided its own financing. Under these arrangements, a participating member has an undivided interest in a utility plant and is responsible for its pro-portionate share of the costs of construction and operation and it is entitled to its proportionate share of the energy produced. All utility plant -of the Authority with the exception of the Magnolia Power Project is jointly owned. The related cost and accumulated depreciation for these jointly-owned projects has been reflected in each project's financial statements in utility plant. Additionally, the Authority's share of expenses for each project is included in the statements of revenues, expenses, and changes in net assets (deficit) as part of operations and maintenance expenses.
Using This Financial Report -
This annual financial report consists of a series of financial statements and reflects the self-supporting activities of the Authority that are funded primarily through the sale of energy and transmission services to member agencies under project specific "take or pay" contracts that require each member agency to pay its proportionate share of operating and maintenance expenses and debt service with respect to such projects.
Combined Financial Statements -
The Combined Financial Statements provide an indication of the Authority's financial health. The Combined Statements of Net Assets (Deficit) include all of the Authority's assets and liabilities, using an accrual basis of accounting, as well as an indication about which assets can be utilized for general purposes and which assets are restricted as a result of bond covenants and other commitments. The Combined Statements of Revenues, Expenses and Changes in Net Assets (Deficit) report all of the revenues and expenses during the time periods indicated. The Combined Statements of Cash Flows report the cash provided and used by operating activities, as well as other cash sources such as investment income, cash payments for bond principal payments, and capital additions and betterments.
22
SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY MANAGEMENT'S DISCUSSION AND ANALYSIS JUNE 30, 2005 Palo Verde Project Financial Highlights (In thousands)
June 30, 2005 2004 Assets Net utility plant......................................................
145,425
$ 164,944 Investm ents.........................................................
250,621 682,699 Cash and cash equivalents.............................................
7,079 160,455 O ther.............................................................
12,601 13,955 Total assets....................................................
415,726
$ 1,022,053 Liabilities and Net Assets Noncurrent liabilities.................................................
167,576
$ 569,050 Current liabilities.....................................................
32,931 125,057 Total liabilities..................................................
200,507 694,107 Net assets Invested in capital assets, net of related debt...........................
27,418 (451,167)
Restricted net assets...............................................
100,084 757,558 Unrestricted net assets.............................................
87,717 21,555 Total net assets................................................
215,219 327,946 Total liabilities and net assets.....................................
415,726
$ 1,022,053 Revenues, Expenses and Changes in Net Assets Operating revenues...................................................
60,341 164,884 Operating expenses..................................................
(66,456)
(63,496)
Operating (loss) incom e..........................................
(6,115) 101,388 Investm ent incom e...................................................
10,511 14,144 Debt expense.......................................................
(8,793)
(42,949)
Loss on extinguishment of debt.........................................
(85,827)
Change in net assets.................................................
(90,224) 72,583 Release of over billings from prior years..................................
(22,503)
Net assets - beginning of year..........................................
327,946 255,363 Net assets - end of year...............................................
$ 215,219
$ 327,946 Net Assets -The PaloVerde Project's net assets decreased by $112.7 million, mainly due to a $606.3 million decrease in assets and a decrease in liabili-ties of $493.6 million.The decrease in the assets and liabilities of the Project is primarily due to the defeasance of the 1987A, 1989A, and 1997B Bonds on July 1, 2004 as part of the Authority's Restructuring Plan.
In 1997, the Authority began taking steps designed to accelerate the payment schedule of all fixed rate subordinate bonds relating to PVNGS so that they would be paid off by July 1,2004 (the "Restructuring Plan"). Certain outstanding bonds were refunded for savings and the project participants acceler-ated payments on the other bonds issued by the Authority for PVNGS. The Restructuring Plan resulted in increased payments (approximately $65 mil-lion per year) from 1997 with the final payment made on July 1, 2004.
After the final payment was made, $512 million of the 1987A, the 1989A, and the 1997B Palo Verde bonds were legally defeased on July 1,2004. This effectively discharged the obligation of-SCPPA participants to pay principal and interest on those bonds and removed the liability for the payment of those bonds from SCPPA's financial statements.
Net Operating (Loss) Income -- The net operating income decreased by $107.5 million primarily due to a decrease in billings to the SCPPA par-ticipants because of the completion of the RLestructuring Plan.
Debt Expense -The decrease of $34 million of debt expense is largely due to the decrease of. interest expense, amortization of bond discounts and loss on refunding related to the defeasance of the 1987A, 1989A, and the 1997B bonds on July 1, 2004.
23
SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY MANAGEMENT'S DISCUSSION AND ANALYSIS JUNE 30, 2005 Loss on Extinguishment of Debt -
The $85.8 million loss on extinguishment of debt resulted from the defeasance of the remaining 1987A, 1989A, and the 1997B Palo Verde Bonds on July 1, 2004. This loss consists of the write-off of the remaining unamortized debt expenses relating to those issues as of the date of the defeasance and the market value of the related investments, which were recorded as ofJune 30, 2004.
Long-term Debt -
The Authority financed the acquisition of the assets of the Palo Verde Project through the issuance of revenue bonds. Currently, capital additions to the Project are financed from revenues received from participants.
The following graph provides an indication of the principal and interest payments on the Palo Verde Project that are due each year following June 30, 2005 until the bonds mature in FiscalYear 2016-2017. Interest is reflected on an accrual basis.
Palo Verde Project Debt Service Requirements Fiscal Year Ending June 30, 2005
($ in thousands) 4 K ~
<-A 1<
1 Beginning in July 1, 2005, interest payments on the remaining bonds are payable on the first business day of each month. Principal maturities of $51.8 and $11.9 million were paid on July 1, 2004 and June 1, 2005, respectively.
24
SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY MANAGEMENT'S DISCUSSION AND ANALYSIS JUNE 30, 2005 Southern Trarnsmission System Project (STS)
Financial Highlights (In thousands)
June 30, 2005 2004 Assets Net utility plant......................................................
322,528 342,156 Investm ents.........................................................
53,136 56,361 Cash and cash equivalents.............................................
36,812 41,034 Other.............................................................
18,989 23,519 Total assets....................................................
431,465 463,070 Liabilities and Net Deficit Noncurrent liabilities.................................................
777,888
$ 795,222 Current liabilities.....................................................
42,119 49,524 Total liabilities..................................................
820,007 844,746 Net deficit Invested in capital assets, net of related debt...........................
(479,463)
(473,464)
Restricted net assets (deficit)........................................
92,660 99,459 Unrestricted net asset (deficit)........................................
(1,739)
(7,671)
Total net deficit.................................................
(388,542)
(381,676)
Total liabilities and net deficit......................................
$ 431,465 463,070 Revenues, Expenses and Changes in Net Deficit Operating revenues...................................................
83,715 72,618 Operating expenses..................................................
(38,182)
(33,371)
Net operating income............................................
45,533 39,247 Investm ent incom e...................................................
3,732 3,044 Debt expense.......................................................
(56,131)
(57,593)
Change in net deficit..................................................
(6,866)
(15,302)
Net deficit - beginning of year..........................................
(381,676)
(366,374)
Net deficit - end of year...............................................
$ (388,542)
$ (381,676)
Net Deficit -
The net deficit in STS increased in 2005 by $6.9 million due to a $31.6 million decrease in total assets and a decrease in liabilities of
$24.7 million. The decrease in total assets consists mainly of the scheduled depreciation of utility plant of $19.6 million.
The decrease in liabilities of $24.7 million is due to the following:
" A decrease of $17.3 million in long-term debt due to maturities net of amortization of bond discounts, premiums and losses on refunding, and
" A decrease of $7.4 million in current liabilities mainly due to a decrease in this fiscal year's over billing adjustment.
25
SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY MANAGEMENT'S DISCUSSION AND ANALYSIS JUNE 30, 2005 Long-term Debt -
The Authority acquired the STS assets through the issuance of revenue bonds. Capital additions are currently financed with rev-enues received from participants. Principal bond maturities redeemed on July 1, 2004 totaled $28.5 million.
Southern Transmission System Project Debt Service Requirements Fiscal Year Ending June 30,2005
($ in thousands)
Hill 7
h1,A 01+hflrI@ýJýýw&m ~
IIII'ir Ii7;2 " 7]
t;*kL The preceding graph provides an indication of the principal and interest payments on the STS Project that are due each year following June 30, 2005 until the bonds mature in FiscalYear 2023-2024. Interest is reflected on an accrual basis.
Interest payments on the bonds are payable semi-annually on July 1 and January I of each year. Principal maturities of $28.5 million were paid on July 1,2004.
Net Operating Income -
The increase in operating income of $6.3 million is due mainly to the decrease in 2004 revenue as a result of a true-up from 2003.
Debt Expense -
The decrease in STS debt expense of $1.5 million is largely due to the decrease in amortization of bond discounts relating to the 1988A and the 1992A Refunding Bonds.
26
SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY MANAGEMENT'S DISCUSSION AND ANALYSIS JUNE 30, 2005 Hoover Uprating Project Financial Highlights (In thousands)
June 30, 2005 2004 Assets Investm ents.........................................................
3,214 2,918 Cash and cash equivalents.............................................
1,008 1,241 Other.............................................................
18,066 19,400 Total assets....................................................
22,288 23,559 Liabilities and Net Assets Noncurrent liabilities.................................................
17,716 18,575 Current liabilities.....................................................
1,639 1,537 Total liabilities..................................................
19,355 20,112 Net assets Restricted net assets...............................................
1,660 2,104 Unrestricted net assets.............................................
1,273 1,343 Total net assets.................................................
2,933 3,447 Total liabilities and net assets......................................
22,288 23,559 Revenues, Expenses and Changes in Net Assets Operating revenues...................................................
2,344 2,554 Operating expenses..................................................
(2,461)
(2,331)
Net operating (loss) incom e.......................................
(117) 223 Investm ent incom e...................................................
119 18 Debt expense.......................................................
(516)
(647)
Change in net assets.................................................
(514)
(406)
Net assets - beginning of year..........................................
3,447 3,853 Net assets-end of year...............................................
2,933 3,447 Net Assets - The net assets of the Hoover Uprating Project decreased by $514,000. The net decrease is primarily due to a decrease in the Advances for capacity and energy balance. This balance consists of $18 million in advances provided by the Participants to the Hoover Power Plant, net of credits pro-vided by the plant manager. In accordance with the agreements, these advances are returned to the Authority through an annual amount of energy and capacity credits billed by the plant. Annual billings decrease the Advances for capacity and energy balance up to the amount of principal paid on debt by the Authority. Credits in excess of principal paid on debt decrease the Project's current year interest expense. During the current year, the project billed SCPPA $2.2 million, of which approximately $1.3 million was used to decrease the Advances balance. The remaining credits of $0.9 million were uti-lized to offet debt expense.
27
SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY MANAGEMENT'S DISCUSSION AND ANALYSIS JUNE 30, 2005 Long-term Debt - The Authority acquired its interest in the Hoover Uprating Project through the issuance of revenue bonds.The following graph pro-vides an indication of the principal and interest payments on the Hoover Uprating Project that are due each year following June 30,2005 until the bonds mature in FiscalYear 2017-2018. Interest is reflected on an accrual basis.
Hoover Uprating Project Debt Service Requirements Fiscal Year Ending June 30,2005
($ in thousands)
II.qMM 18TO 01 ff~
Interest payments on the bonds are payable semi-annually on October 1 and April 1 of each year. Principal maturities of $1.2 million were paid on October 1, 2004.
28
SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY MANAGEMENT'S DISCUSSION AND ANALYSIS JUNE 30, 2005 Mead-Phoenix Project Financial Highlights (In thousands)
June 30, 2005 2004 Assets Net utility plant......................................................
40,056 41,394 Investm ents.........................................................
8,765 8,709 Cash and cash equivalents.............................................
1,443 1,768 O ther.............................................................
5,940 5,638 Total assets....................................................
56,204 57,509 Liabilities and Net Deficit Noncurrent liabilities.................................................
65,934 65,463 Current liabilities.....................................................
1,323 1,458 Total liabilties..................................................
67,257 66,921 Net deficit Invested in capital assets, net of related debt............................
(24,946)
(23,013)
Restricted net assets...............................................
13,911 13,508 Unrestricted net assets (deficit).......................................
(18) 93 Total net deficit.................................................
(11,053)
(9,412)
Total liabilities and net deficit......................................
56,204 57,509 Revenues, Expenses and Changes in Net Deficit Operating revenues.......................................
3,854 4,679 Operating expenses..................................................
(2,530)
(2,470)
Net operating incom e............................................
1,324 2,209 Investm ent incom e...................................................
663 700 Debt expense.......................................................
(3,628)
(4,240)
Loss on refunding of debt..............................................
(127)
Change in net deficit..................................................
(1,641)
(1,458)
Net deficit - beginning of year..........................................
(9,412)
(7,954)
Net deficit - end of year...............................................
(11,053)
(9,412)
Net Deficit - Net deficit of the Mead-Phoenix Project increased by $1.6 million mainly due to the scheduled depreciation of utility plant of $1.4 million.
29
SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY MANAGEMENT'S DISCUSSION AND ANALYSIS JUNE 30, 2005 Long-term Debt - The acquisition of the assets of the Mead-Phoenix Project was provided by a transfer of funds fiom the Multiple Project Fund (See Note I of the Notes to Combined Financial Statements). In March 1994, the Authority issued Mead-Phoenix Project Revenue Bonds to advance refund a portion of the Multiple Project Fund Bonds. In May 2004, the Authority issued new refunding bonds as follows:
Description of Bonds Par Amount of Par Amount of Debt Service Refunded Bonds Refunding Issue Savings Net Present Bond Ratings Value Savings by S&P/Moody's Mead-Phoenix Project Revenue Bonds 2004 Series A
$ 42,235,000
$ 42,225,000
$4,081,649
$ 2,928,381 AAA/Aaa The following graph provides an indication of the principal and interest payments on the Mead-Phoenix Project that are due each year following June 30, 2005 until the bonds mature in FiscalYear 2020-2021. Interest is reflected on an accrual basis.
Mead-Phoenix Project Debt Service Requirements Fiscal Year Ending June 30,2005
($ in thousands)
VfM10 40[!$
2~
II 1I~i't~t' ~
I I.
~Il ~
f
_ LU ft.
ft
~!t Interest payments on the bonds are payable semi-annually on July 1 andJanuary 1 of each year.There were no principal maturities for the year endedJune 30,2005.
30
SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY MANAGEMENT'S DISCUSSION AND ANALYSIS JUNE 30, 2005
.Mead-Adelanto Project Financial Highlights (In thousands)
June 30, 2005 2004 Assets Net utility plant......................................................
131,032 135,531 Investm ents.........................................................
24,130 23,893 Cash and cash equivalents.............................................
3,731 3,976 O ther.............................................................
16,772 16,070 Total assets....................................................
175,665 179,470 Liabilities and Net Deficit Noncurrent liabilities.................................................
212,155 210,861 Current liabilities.....................................................
3,815 3,522 Total liabilities..................................................
215,970 214,383 Net deficit Invested in capital assets, net of related debt............................
(78,036)
(71,830)
Restricted net assets...............................................
37,882 36,073 Unrestricted net assets (deficit).......................................
(151) 844 Total net deficit.................................................
(40,305)
(34,913)
Total liabilities and net deficit......................................
175,665 179,470 Revenues, Expenses and Changes in Net Deficit Operating revenues...................................................
10,237 13,552 Operating expenses..................................................
(6,213) 6,597)
Net operating income............................................
4,024 6,955 Investm ent incom e...................................................
1,814 1,844 Debt expense.......................................................
(11,230)
(13,215)
Loss on refunding of debt..............................................
(381)
Change in net deficit..................................................
(5,392)
(4,797)
Net deficit - beginning of year..........................................
(34,913)
(30,116)
Net deficit - end of year...............................................
(40,305)
(34,913)
Net Deficit - The net deficit of the Mead-Adelanto Project increased by $5.3 million mainly due to the scheduled depreciation on utility plant of $4.5 million.
31
SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY MANAGEMENT'S DISCUSSION AND ANALYSIS JUNE 30, 2005 Long-term Debt - Similar to the Mead-Phoenix Project, the interest in the Mead-Adelanto Project was acquired by the Authority through a transfer of funds, and the bonds issued to obtain these funds, from the Multiple Project Fund (See Note 1 of the Notes to Combined Financial Statements). In March 1994, the Authority issued Mead-Adelanto Project Kevenue Bonds to advance refund the Multiple Project Fund Bonds. In May 2004, the Authority issued new refunding bonds as follows:
Par Amount of Par Amount of Debt Service Refunded Bonds Refunding Issue Savings Net Present Bond Ratings Value Savings byS&P/Moody's Description of Bonds Mead-Adelanto Project Revenue Bonds 2004 Series A
$141,155,000
$141,150,000
$13,645,006
$9,798,503 AAA/Aaa The following graph provides an indication of the principal and interest payments on the Mead-Adelanto Project that are due each year following June 30, 2005 until the bonds mature in FiscalYear 2020-2021. Interest is reflected on an accrual basis.
Mead-Adelanto Project Debt Service Requirements Fiscal Year Ending June 30, 2005
($ in thousands)
Interest payments on the bonds are payable semi-annually on July 1 and January 1 of each year. There were no principal maturities for the year ended June 30, 2005.
32
SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY MANAGEMENT'S DISCUSSION AND ANALYSIS JUNE 30, 2005 Multiple Project Fund Financial Highlights (In thousands)
June 30, 2005 2004 Assets Investm ents.........................................................
$ 233,873 238,839 Other.............................................................
8,322 8,504 Total assets....................................................
242,195
$ 247,343 Uabilities and Net Assets Noncurrent liabilities.................................................
$ 202,104
$ 209,524 Current liabilities......................................................
32 491 30,712 Total liabilities..................................................
234,595 240,236 Net assets Restricted net assets...............................................
7,600 7,107 Total net assets.................................................
7,600 7,107 Total liabilities and net assets......................................
242,195 247,343 Revenues, Expenses and Changes in Net Assets Investm ent incom e...................................................
16,582 16,973 Debt expense.......................................................
(16,089)
(16,558)
Change in net assets.................................................
493 415 Net assets - beginning of year..........................................
7,107 6,692 Net assets - end of year...............................................
7,600 7,107 NetAssets - The increase in net assets of $493,000 is primarily due to a $5.6 million decrease in total liabilities representing primarily payment of prin-cipal maturities during the fiscal year, which is partially offset by a $5.0 million net decrease in investments drawn down to pay for such principal matu-rities.The increase in net assets represents the difference between investment income earned on bond proceeds deposited in the Multiple Project Fund and the debt expense on such bonds.
33
SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY MANAGEMENT'S DISCUSSION AND ANALYSIS JUNE 30, 2005 Long-term Debt -The Multiple Project Fund was established by the issuance of revenue bonds. The bond proceeds are to be used to finance costs of con-struction and acquisition of ownership interests or capacity rights in one or more projects that the Authority expects to undertake. Certain of these funds were used to finance the Authority's interest in the Mead-Phoenix and Mead-Adelanto Projects (See Note 1 of the Notes to Combined Financial Statements).
The following graph provides an indication of the principal and interest payments on the Multiple Project Fund that are due each year followingJune 30, 2005 until the bonds mature in FiscalYear 2020-2021. Interest is reflected on an accrual basis.
Multiple Project Fund Debt Service Requirements Fiscal Year Ending June 30, 2005
($ in thousands)
Interest payments on the bonds are payable semi-annually on July I and January 1 of each year. Par value of bonds that matured and were redeemed on July 1, 2004 was $7.6 million. A total of $50.2 million of the outstanding Multiple Project R1evenue Bonds are not subject to redemption prior to matu-rity.
34
SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY MANAGEMENT'S DISCUSSION AND ANALYSIS JUNE 30. 2005 San Juan Project Financial Highlights JIn thousands)
June 30, 2005 2004 Assets Net utility plant......................................................
57,975 70,452 Investm ents.........................................................
31,351 26,944 Cash and cash equivalents.............................................
14,518 12,671 O ther.............................................................
18,509 10,442 Total assets....................................................
122,353 120,509 Liabilities and Net Deficit Noncurrent liabilities.................................................
197,459 191,277 Current liabilities.....................................................
17,890 18,317 Total liabilities..................................................
215,349 209,594 Net deficit Invested in capital assets, net of related debt and deferred credit..............
(130,894)
(127,557)
Restricted net assets...............................................
32,529 29,722 Unrestricted net assets.............................................
5,369 8,750 Total net deficit.................................................
(92,996)
(89,085)
Total liabilities and net deficit......................................
122,353 120,509 Revenues, Expenses and Changes in Net Deficit Operating revenues...................................................
60,322 61,735 Operating expenses..................................................
(56,084)
(57,704)
Net operating incom e..............................................
4,238 4,031 Investm ent incom e...................................................
1,547 1,321 Debt expense.......................................................
(9,696)
(10,138)
Change in net deficit..................................................
(3,911)
(4,786)
Net deficit - beginning of year..........................................
(89,085)
(84,299)
Net deficit - end of year...............................................
(92,996)
(89,085)
Net Deficit - The net deficit of the San Juan Project increased by $3.9 million, primarily due to an increase of $1.8 million in total assets and an increase in total liabilities of $5.7 million. The decrease in total assets is largely due to the scheduled depreciation on utility plant of $10.2 millionThe decrease in assets was offset mainly by the $8.8 million reduction in long-term debt representing maturity payments during the fiscal year.
35
SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY MANAGEMENT'S DISCUSSION AND ANALYSIS JUNE 30, 2005 Long-term Debt - The Authority financed its acquisition of the assets of the San Juan Project by the issuance of revenue bonds. Currently, capital addi-tions are financed from revenues received from participants. In May 2005, the Authority issued new refunding bonds as follows:
Par Amount of Par Amount of Refunded Bonds Refunding Issue Debt Service Net Present Bond Ratings Savings Value Savings by S&PlMoody's Description of Bonds San Juan Project Revenue Bonds 2005 Refunding Series A
$ 71,850,000
$ 71,880,000
$10,026,571
$ 6,669,244 AAA/Aaa The following graph provides an indication of the principal and interest payments on the San Juan Project that are due each year followingJune 30,2005 until the bonds mature in FiscalYear 2019-2020. Interest is reflected on an accrual basis.
San Juan Project Debt Service Requirements Fiscal Year Ending June 30, 2005
($ in thousands)
OilI i
IJh Interest payment on the bonds are payable senmi-annually on July I andJanuary 1 of each year. Principal maturities of $8.8 million were paid on January 1,2005.
36
SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY MANAGEMENT'S DISCUSSION AND ANALYSIS JUNE 30, 2005 Magnolia Power Project Financial Highlights (In thousands)
June 30, 2005 2004 Assets Net utility plant.......................................................
289,276 203,703 Investm ents..........................................................
35,080 128,425 Cash and cash equivalents...............................................
19,169 7,883 O ther...............................................................
5,758 6 106 Total assets.....................................................
349 283 346,117 Liabilities and Net Assets Long-term debt........................................................
320,909 321,327 Current liabilities......................................................
28,374 24,790 Total liabilities...................................................
349,283 346,117 Net assets Invested in capital assets, net of related debt.............................
28,013 (103,986)
Restricted net assets.................................................
(28,013) 103,986 Unrestricted net assets...............................................
Total net assets..................................................
Total liabilities and net assets.......................................
349,283 346,117 Magntolia Power Project Background - In 2000, the City of Burbank (the "City"), an Authority member, initiated a study to determine the requirements for replacing an aging power plant within the city limits. A decision was reached that it would be more economical to build a plant with more capacity than would be required to meet the City's power demands. The City introduced the idea to the Authority and four members, the Cities of Anaheim, Colton, Glendale, and Pasadena (the "Project A Participants"), expressed their interest in joining the City of Burbank in pursuing the Project. The City of Cerritos (the "Project B Participant") also joined in the development of the project when it became a member of the Authority in July 2001.
In March 2003, the California Energy Commission gave its approval for construction of the Magnolia Power Project.The Project is a natural gas-fired generator and is designed to generate 242 megawatts to meet base load capacity, but will be able to generate more than 300 megawatts for short periods of time during peak demand periods.The plant is the first to be solely-owned by the Authority, and the City of Burbank has managed its construction and is the operating agent for the Project. To finance the Project, the Authority issued $300.0 million of Magnolia Power Project A, Revenue Bonds, 2003-1 and $14.1 million of Magnolia Power Project B, Lease Revenue Bonds (City of Cerritos, California) 2003-1 in April 2003 (Refer to Note 5 of the Notes to Combined Financial Statements).
To date, the Project has no revenues and is not anticipated to have any until the Project becomes operational. During the 2005 fiscal year, additional costs related to the construction of the plant of $72.2 million anid debt service costs of $15.1 million offset by investment income of $1.8 million, were capi-talized as part of the utility plant balance. Once the plant becomes operational, these costs will be recovered through future billings to participants.
Long-term Debt -
The following graph provides an indication of the principal and interest payments on the Project that are due each year on July 1 until the bonds mature in FiscalYear 2036-2037. Interest is reflected on an accrual basis.
37
SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY MANAGEMENT'S DISCUSSION AND ANALYSIS JUNE 30, 2005 Magnolia Power Project Debt Service Requirements Fiscal Year Ending June 30,2005
($ in thousands)
~~~~1fo 4
d I
n rn wT1~~H f~
h T
Interest payments on the bonds are payable semi-annually on July 1 and January 1 of each year. There were no principal maturities for the year ended June 30, 2005.
Projects' Stabilization Fund In 1996, the Board adopted a resolution to establish the Projects' Stabilization Fund. Monies deposited by the participants to this Fund are used to pay for Authority costs as directed by the Participants (See Note 1 of the Notes to Combined Financial Statements). AtJune 30, 2005 the Fund had a bal-ance of $74.1 million.
Financial Outlook The Authority's credit strength is based on:
The collective credit strengths of each project participant; The absence of concentration risk as evidenced by the lack of substantial reliance by one participant on the resources financed; The low cost power the Projects provide the participants; and, Strong legal provisions.
The Authority has take-or-pay power sales and transmission service contracts which unconditionally require the Participants to pay for the cost of oper-ating and maintaining the Projects, including debt service, whether or not the Projects are operating or operable. Although the contracts have not been court-tested, a municipal utility's authority to enter into such contracts is rooted in the State's constitutional provisions for municipal electric utilities.
The Authority continues to play an important role as a legislative advocate and its focused strategic plan continues to provide benefits to member agen-cies as they prepare for increased competition. The Authority's management continues to focus on lowering the fixed costs of its projects to ensure the flexibility needed to perform in a more competitive marketplace. During the fiscal year, the Authority refunded $71.8 million of the Authority's long-term debt, which generated $6.7 debt service savings. Over the last three years, market opportunities allowed the Authority to save $115.3 million in gross debt service having a present value of $75.9 million by restructuring its debt obligations.
38
SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY MANAGEMENT'S DISCUSSION AND ANALYSIS JUNE 30, 2005 Natural Gas Reserve Acquisition Project - Several SCPPA members, including LADWP, the cities ofAnaheim, Burbank, Colton, Glendale, and Pasadena, in addition to Turlock Irrigation District, realized one of their goals in acquiring natural gas reserves for their own generating facilities.
On July 1,2005, the acquisition of natural gas reserves and other real property from Anschutz Corporation in Pinedale,Wyoming was successfully com-pleted. The transaction totaled in excess of $300 million. SCPPA financed approximately $26 million on behalf ofAnaheim, Burbank, and Colton. The other participants in the project, LADWP, Glendale, Pasadena, and the Turlock Irrigation District, completed the financing of this project. Gas began to flow to the participants at 12:01 a.m. on July 1, 2005.
This is a unique project and is believed to be the largest natural gas field owned by public power utilities and should assure the participants a secure long-term and stable supply of natural gas to fuel the various power plants. All of the participants, except for the Turlock Irrigation District, have agreed to pool operations under an agreement with SCPPA to assure close coordination and operation efficiencies.
Renewable Projects - SCPPA members are committed to the use of renewable energy resources in the future.
Energy from the High Winds Energy Center in Solano County, California, is now a part of the participating members' resource portfolios. SCPPA mem-bers, including the cities of Anaheim, Azusa, Colton, Glendale, and Pasadena, contracted with PPM Energy (a division of Pacificorp Holdings) for 30 megawatts (MW) of the 150 MW wind facility. PPM also provided a firming service, which guaranteed SCPPA members firm delivery of energy, at pre-determined rates, regardless of the wind conditions at the site.Although the purchase contracts under the project were between the individual members and PPM, SCPPA played a key role in bringing this project to a reality through the issuance of the Renewable RFP and coordinating contract negotiations.
SCPPA has entered into a Power Purchase Agreement with Ameresco Chiquita Energy LLC for 100% of the electric generation from a landfill gas to energy facility to be located at the landfill site inValencia, California (Ameresco Landfill Gas to Energy Project).The SCPPA participants in this project include the cities ofAnaheim, Burbank, Glendale, and Pasadena, with their respective shares listed below.This project, which is expected to go on-line in early 2006, will initially be for 13.4 Megawatts with two options to increase the output by an additional 10 Megawatts in the future when additional gas becomes available.
PARTICIPANTS CONTRACT SHARE City of Anaheim..........................
33.3333%
City of Burbank..........
. 16.6667%
City of Glendale.....
. 33.3333%
City of Pasadena.........
. 16.6667%
SCPPA has also entered into Power Purchase Agreements with divisions of Ormat Technologies, Inc. for 20 megawatts of electric generation from geot-hermal energy facilities to be located in Heber and Ormesa, California. The SCPPA participants in this project include the cities of Anaheim, Banning, Glendale, and Pasadena, with their respective shares listed below.This project is expected to start delivery of 10 MW in November 2005 from the Heber facility and the second 10 MW in November 2006 from the Ormesa facility PARTICIPANTS CONTRACT SHARE City of Anaheim............................ 69%
City of Banning............................. 1%
City of Glendale............................ 15%
City of Pasadena........................... 15%
Summary - The management of the Authority is responsible for preparing the information in this management discussion and analysis, combined financial statements and notes to combined financial statements. We prepared the financial statements according to accounting principles generally accepted in the United States of America, and they fairly portray the Authority's financial position and operating results. The notes to the financial statements are an integral part of the basic financial statements and provide additional financial information.
39
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40
REPORT OF INDEPENDENT AUDITORS MOSS-A11hk LIPu To the Board of Directors and Participants of the Southern California Public Power Authority We have audited the accompanying combined statements of net assets (deficit) of Southern California Public Power Authority (the Authority) as ofJune 30,2005 and the related combined statements of revenues, expenses and changes in net assets (deficit) and cash flows for the year then ended. These financial statements are the responsibility of the Authority's management. Our responsibility is to express an opinion on these financial statements based on our audit. The accompanying combined statements of net assets (deficit) of Southern California Public Power Authority as ofJune 30,2004 and the related combined statements of revenues, expenses and changes in net assets (deficit) and cash flows for the year then ended were audited by other auditors whose report dated September 16, 2004 expressed an unqualified opinion on those statements.
We conducted our audit in accordance with auditing standards generally accepted in the United States ofAmerica. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.
An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Southern California Public Power Authority as ofJune 30, 2005 and the results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.
The management's discussion and analysis preceding the combined financial statements is not a required part of the basic financial state-ments but is supplementary information required by the Governmental Accounting Standards Board. We have applied certain limited pro-cedures, which consisted principally of inquiries of management regarding the methods of measurement and presentation of the required supplementary information. However, we did not audit the information and express no opinion on it.
The additional supplemental information following the combined financial statements and notes to combined financial statements is also not a required part of the basic financial statements but is supplementary information provided for purposes of additional analysis. We did not audit or perform any other procedures on this information and express no opinion on it.
Vancouver, Washington August 26,2005 41
SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY COMBINED STATEMENTS OF NET ASSETS (DEFICIT)
JUNE 30, 2005 (Amounts in thousands)
June 30, 2005 Southern Palo Transmission Hoover Mead-Mead-Multiple San Magnolia Projects' Verde System Uprating Phoenix Adelanto Project Juan Power Stabilization Proiect Proiect Proaect Project Project Fund Project Project Fund Total Total Eliminations Combined ASSETS Noncurrent assets Utility plant Production Transmission General Less - accumulated depreciation
$ 636,588 $
14,057 674,606 2,668 18,911 653,313 693,517 53919 inn N 9£q 21 21 71 50,770 2,640 53,410 1 3 4.31
$ 173,592 $
172,319 473 7,422 172,792 181,014 41l 7Rfl 1743t7
$ 810,180 $
911,752 32,135 1,754,067
-1 1n0897R9
$ 810,180 911,752 32,135 1,754,067 1n089769 Construction work in progress Nuclear fuel, at amortized cost Net utility plant Special funds Restricted investments Escrow accounts Decommissioning funds Other funds Total restricted investments Unrestricted investments Other funds Total special funds Other noncurrent assets Advance to IPA - restricted Advances for capacity and' energy, net - restricted Deferred debit Unamortized debt expenses Total other noncurrent assets Total noncurrent assets Current assets Special funds Cash/cash equivalents -restricted Cash/cash equivalents -unrestrict Interest receivable Accounts receivable Due from other project - restricted Materials and supplies Total current assets Total assets 114,123 322,528 39,979 131,032 56,636 664,298 664,298 16,650 77 1,339 289,276 307,342 307,342 14,652 14,652 14,652 145,425 322,528 40,056 131,032 57,975 289,276 986,292 986,292 10,545 10,545 10,545 131,991 131,991 131,991 32,038 42,591 2,654 8,765 24,130 233,873 31,351 35,080 49,116 459,598 459,598 164,029 53,136 2,654 8,765 24,130 233,873 31,351 35,080 49,116 602,134 602,134 86,592 560 87,152 87,152 250,621 53,136 3,214 8,765 24,130 233,873 31,351 35,080 49,116 689,286 689,286 11,550 11,550 11,550 17,710 17,710 17,710 13,000 13,000 13,000 1,136 7,367 330 931 3,088 2,009 5,397 20,258 20,258 1,136 18,917 18,040 931 3,088 15,009 5,397 62,518 62,518 397,182 394,581 21,254 49,752 158,250 233,873 104,335 329,753 49,116 1,738,096 1,738,096 5,247 36,160 179 1,181 3,007 4,766 19,169 24,480 94,189 94,189
[ed 1,832 652 829 262 724 9,752 14,051 14,051 1,426 28 26 323 888 8,322 44 333 517 11,907 11,907 3,390 44 30 (7) 120 28 3,605 3,605 4,656 12,803 17,459 (17,459) 6,649 3,336 9,985 9,985 18,544 36,884 1,034 6,452 17,415 8,322 18,018 19,530 24,997 151,196 (17,459) 133,737
$ 415,726 $ 431,465 $ 22,288 $
56,204 $ 175,665 $ 242,195 $ 122,353 $ 349,283 $
74,113 $1,889,292 $ (17,459) $1,871,833 LIABILITIES Noncurrent liabilities Long-term debt Notes payable Deferred credit Total noncurrent liabilities Current liabilities Debt due within one year Notes payable due within one year Accrued interest Accounts payable and accruals Accrued property tax Due to other projects Total current liabilities Total liabilities NET ASSETS (DEFICIT)
Invested in capital assets, net of related debt and deferred credits Restricted net assets (deficit)
Unrestricted net assets (deficit)
Total net assets (deficit)
$ 107,707 $ 777,888 $
17,716 $
65,934 $ 212,155 $ 202,104 $ 181,459 $ 320,909 $
$1,885,872 $
$ 1,885,872 59,869 59,869 59,869 16,000 16,000 16,000 167,576 777,888 17,716 65,934 212,155 202,104 197,459 320,909 1,961,741 1,961,741 11,300 31,470 1,275 8,100 9,160 61,305 61,305 4,307 4,307 4,307 1,419 8,214 244 1,013 2,946 6,932 3,632 7,585 31,985 31,985 14,105 2,435 120 310 869 4,834 20,789 43,462 43,462 1,800 264 2,064 2,064 17,459 17,459 (17,459) 32,931 42,119 1,639 1,323 3,815 32.491 17,890 28,374 160,582 (17,459) 143,123 200,507 820,007 19,355 67,257 215,970 234,595 215,349 349,283 2,122,323 (17,459) 2,104,864 27,418 (479,463)
(24,946)
(78,036)
(130,894) 28,013 (657,908)
(657,908) 100,084 92,660 1,660 13,911 37,882 7,600 32,529 (28,013) 74,113 332,426 332,426 87,717 (1,739) 1,273 (18)
(151) 5,369 92,451 92,451 215,219 (388,542) 2,933 (11,053)
(40,305) 7,600 (92,996) 74,113 (233,031)
(233,031)
Total liabilties and net assets (deficit)
$ 415,726 $ 431,465 $
22,288 $
56,204 $ 175,665 $ 242,195 $ 122,353 $ 349,283 $
74,113 $1,889,292
$ (17,459) $ 1,871,833 42 The accompanying notes are an integral part of the combined financial statements.
SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY COMBINED STATEMENTS OF NET ASSETS (DEFICIT)
JUNE 30, 2004 (Amounts in thousands)
June 30, 2004 Southern Palo Transmission Hoover Mead-Mead-Multiple San Magnolia Projects' Verde System Uprating Phoenix Adelanto Project Juan Power Stabilization Proiect Proiect Proiect Proiect Proiect Fund Proiect Proiect Fund Total Total Eliminations Combined ASSETS Noncurrent assets Utility plant Production Transmission General Less - accumulated depreciation Construction work in progress Nuclear fuel, at amortized cost Net utility plant Special funds Restricted investments Escrow accounts Decommissioning funds Other funds Total restricted investments Unrestricted investments Other funds Total special funds Other noncurrent assets Advance to IPA - restricted Advances for capacity and energy, net -restricted Unamortized debt expenses Total other noncurrent assets Total noncurrent assets
$ 634,940 $
171,781 $
806,721 $
$ 806,721 14,062 674,606 50,770 172,319 911,757 911,757 2,699 18,911 21 2,640 473 7,425 32,169 32,169 651,701 693,517 21 53,410 172,792 179,206 1,750,647 1,750,647 511,016 351,361 21 12,028 37,261 111,282 1,022,969 1,022,969 140,685 342,156 41,382 135,531 67,924 727,678 727,678 9,950 12 2,528 203,703 216,193 216,193 14,309 14,309 14,309 164,944 342,156 41,394 135,531 70,452 203,703 958,180 958,180 481,730 10,354 492,084 492,084 126,943 126,943 126,943 53,524 46,007 2,358 8,709 23,893 238,839 26,944 128,425 49,935 578,634 578,634 662,197 56,361 2,358 8,709 23,893 238,839 26,944 128,425 49,935 1,197,661 1,197,661 20,502 560 21,062 21,062 682,699 56,361 2,918 8,709 23,893 238,839 26,944 128,425 49,935 1,218,723 1,218,723 11,550 11,550 11,550 18,974 18,974 18,974 4,854 8,136 399 1,055 3,500 2,330 5,755 26,029 26,029 4,854 19,686 19,373 1,055 3,500 2,330 5,755 56,553 56,553 852,497 418,203 22,291 51,158 162,924 238,839 99,726 337,883 49,935 2,233,456 2,233,456 Current assets Special funds Cash/cash equivalents-restricted 155,285 38,048 Cash/cash equivalents - unrestricted 5,170 2,986 Interest receivable 1,387 26 Accounts receivable 929 3,807 Due from other project - restricted Materials and supplies 6,785 Total current assets 169,556 44,867 410 831 27 1 288 1,247 2,680 521 1,296 339 900 4,244 11,670 6,351 16,546 8,504 2 5n4 7,826 4,845 48 4,798 3,266 70783 7,883 955 214,334 15,649 351 565 12,147 9,534 15,914 10,051 8 234 1 52 277629 214,334 15,649 12,147 9,534 (15,914) 10,051 1159141 261715 1268 n,
1,.
13-Total assets
$1,022,053 $ 463,070 $ 23,559 $ 57,509 $ 179,470 $ 247,343 $ 120,509 $ 346,117 $
51,455 $2,511,085 $ (15,914) $ 2,495,171 LIABILITIES Noncurrent liabilities Long-term debt Total noncurrent liabilities Current liabilities Debt due within one year Accrued interest Accounts payable and accruals Accrued property tax Due to other projects Total current liabilities Total liabilities NET ASSETS (DEFICIT)
Invested in capital assets, net of related debt Restricted net assets Unrestricted net assets (deficit)
Total net assets (deficit)
$ 569,050 $ 795,222 $
18,575 $ 65,463 $ 210,861 $ 209,524 $ 191,277 $ 321,327 $
$2,381,299 $
$ 2,381,299 569,050 795,222 18,575 65,463 210,861 209,524 191,277 321,327 2,381,299 2,381,299 51,800 28,535 1,230 7,600 8,805 97,970 97,970 5,933 6,525 255 1,030 3,070 7,198 5,095 7,585 36,691 36,691 65,776 14,464 52 428 452 4,052 17,205 102,429 102,429 1,548 365 1,913 1,913 15,914 15,914 (15,914) 125,057 49,524 1,537 1,458 3,522 30,712 18,317 24,790 254,917 (15,914) 239,003 694,107 844,746 20,112 66,921 214,383 240,236 209,594 346,117 2,636,216 (15,914) 2,620,302 (451,167)
(473,464)
(23,013)
(71,830)
(127,557)
(103,986)
(1,251,017)
(1,251,017) 757,558 99,459 2,104 13,508 36,073 7,107 29,722 103,986 51,455 1,100,972 1,100,972 21,555 (7,671) 1,343 93 844 8,750 24,914 24,914 327,946 (381,676) 3,447 (9,412)
(34,913) 7,107 (89,085) 51,455 (125,131)
(125,131)
Total liabilties and net assets
$1,022,053 $ 463,070 $ 23,559 $ 57,509 $ 179,470 $ 247,343 $ 120,509 $ 346,117 $
51,455 $2,511,085 $ (15,914) $ 2,495,171 The accompanying notes are an integral part of the combined financial statements.
43
SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY COMBINED STATEMENTS OF REVENUES, EXPENSES AND CHANGES IN NET ASSETS (DEFICIT)
FOR THE YEAR ENDED JUNE 30, 2005 (Amounts in thousands)
Year Ended June 30. 2005 Southern Palo Transmission Hoover Mead-Mead-Multiple San Magnolia Projects' Verde System Uprating Phoenix Adelanto Project Juan Power Stabilization Project Project Project Project Project Fund Project Project Fund Total Operating revenues Sales of electric energy Sales of transmission services Total operating revenues Operating expenses Operations and maintenance Depreciation Amortization of nuclear fuel Decommissioning Total operating expenses Operating income (loss)
Non operating revenues (expenses)
Investment income Debt expense Loss on extinguishment of debt Net non operating revenues (expenses)
Change in net assets (deficit)
Net assets (deficit) - beginning of year Release of over billings from prior years Net contribution by participants Net assets (deficit) - end of year 60,341 $
83,715 2,344 $
60,322 $
3,854 10,237 123,007 97,806 60,341 83,715 2,344 3,854 10,237 60,322 220,813 29,229 18,553 2,461 1,127 1,713 42,755 95,838 18,086 19,629 1,403 4,500 10,216 53,834 8,241 8,241 10,900 3,113 14,013 66,456 38,182 2,461 2,530 6,213 56,084 171,926 (6,115) 45,533 (117) 1,324 4,024 4,238 48,887 10,511 3,732 119 663 1,814 16,582 1,547 1,663 36,631 (8,793)
(56,131)
(516)
(3,628)
(11,230)
(16,089)
(9,696)
(106,083)
(85,827)
(85,827)
(84,109)
(52,399)
(397)
(2,965)
(9,416) 493 (8,149) 1,663 (155,279)
(90,224)
(6,866)
(514)
(1,641)
(5,392) 493 (3,911) 1,663 (106,392) 327,946 (381,676) 3,447 (9,412)
(34,913) 7,107 (89,085) 51,455 (125,131)
(22,503)
(22,503) 20,995 20,995 215,219 $
(388,542) $
2.933 $
(11e053) $
(40.305) $
7,600 $
(92,996) $
74,113 $ (233.031)
The accompanying notes are an integral part of the combined financial statements.
44
SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY COMBINED STATEMENTS OF REVENUES, EXPENSES AND CHANGES IN NET ASSETS (DEFICIT)
FOR THE YEAR ENDED JUNE 30, 2004 (Amounts in thousands)
Year Ended June 30,2004 Southern Palo Transmission Hoover Mead-Mead-Multiple San Magnolia Projects' Verde System Uprating Phoenix Adelanto Project Juan Power Stabilization Project Project Project Project Project Fund Project Project Fund Total Operating revenues Sales of electric energy Sales of transmission services Total operating revenues Operating expenses Operations and maintenance Depreciation Amortization of nuclear fuel Decommissioning Total operating expenses Operating income Non operating revenues (expenses)
Investment income Debt expense Loss on refunding of debt Net non operating revenues (expenses)
Change in net assets (deficit)
Net assets (deficit)- beginning of year Net withdrawals by participants Net assets (deficit) - end of year 164,884 $
2,554 $
72,618 4,679 61,735 $
229,173 90,849 13,552 164,884 72,618 2,554 4,679 13,552 61,735 320,022 26,767 13,743 2,331 1,066 2,097 44,382 90,386 17,946 19,628 1,404 4,500 10,209 53,687 7,883 7,883 10,900 3,113 14,013 63,496 33,371 2,331 2,470 6,597 57,704 165,969 101,388 39,247 223 2,209 6,955 4,031 154,053 14,144 3,044 18 700 1,844 16,973 1,321 379 38,423 (42,949)
(57,593)
(647)
(4,240)
(13,215)
(16,558)
(10,138)
(145,340)
(127)
(381)
(508)
(28,805)
(54,549)
(629)
(3,667)
(11,752) 415 (8,817) 379 (107,425) 72,583 (15,302)
(406)
(1,458)
(4,797) 415 (4,786) 379 46,628 255,363 (366,374) 3,853 (7,954)
(30,116) 6,692 (84,299) 96,421 (126,414)
(45,345)
(45,345) 327,946 $
(381.676) $
3,447 $
(9,412) $
(34,913) $
7,107 $
(89,085) $
51,455 $ (125,131)
The accompanying notes are an integral part of the combined financial statements.
45
SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY COMBINED STATEMENTS OF CASH FLOWS FOR THE YEAR ENDED JUNE 30, 2005 (Amounts in thousands)
Year Ended June 30, 2005 Southern Palo Transmission Hoover Mead-Mead-Multiple San Magnolia Projects' Verde System Uprating Phoenix Adelanto Project Juan Power Stabilization Project Project Project Project Project Fund Project Project Fund Total Cash flows from operating activities Receipts from participants Payments to operating managers Other receipts Net cash flows from operating activities 49,438 $
71,742 $
2,401 $
(29,415)
(14,761)
(226) 3,533 3,707 $
(1,304) 116 10,649 $
(1,881) 67,626 $
(41,240) 205,563 (88,827) 3 649 116 23,556 56,981 2,175 2,519 8,768 26,386 120,385 Cash flows from noncapital financing activities Advances (withdrawals) by participants, net 9,631 20,996 30,627 Cash flows from capital financing activities Additions to plant, net (20,189)
(65)
(-
1,394)
(78,397)
(100,045)
Debt interest payments (6,686)
(39,615)
(998)
(3,349)
(10,469)
(14,130)
(10,189)
(15,170)
(100,606)
Proceeds from sale of bonds 78,084 78,084 Payment for defeasance of revenue bonds (78,454)
(78,454)
Principal payments on debt (63,680)
(28,535)
(1,230)
(7,600)
(8,805)
(109,850)
Transfer of funds to escrow (43,827)
(43,827)
Payment for bond issue costs (49)
(128)
(924)
(1,101)
Net cash used for capital and related financing activities (134,382)
(68,150)
(2,228)
(3,463)
(10,597)
(21,730)
(21,682)
(93,567)
(355,799)
Cash flows from investing activities Interest received on investments 1,648 3,157 95 666 1,804 16,763 1,447 1,814 1,624 29,018 Purchases of investments (90,071)
(29,245)
(1,010)
(1,047)
(2,190)
(1,340)
(27,790)
(929)
(5,500)
(159,122)
Proceeds from sale/maturity of investments 45,873 33,035 735 1,000 1,970 6,307 23,486 94,337 6,405 213.148 Net cash provided by (used for) investing activities (42,550) 6,947 (180) 619 1,584 21,730 (2,857) 95,222 2,529 83,044 Net increase (decrease) in cash and cash equivalents (153,376)
(4,222)
(233)
(325)
(245) 1,847 11,286 23,525 (121,743)
Cash/cash equivalents, beginning of year 160,455 41,034 1 741 1 799 2q79 17271 7 B83 955 279 992 1241 1768 3976 955 229983 Cash/cash equivalents, end of year 7,079 $
36,812 $
1.008 $
1.443 $
3.731 $
14.518 $
19,169 $
24,480 $
108,240 Reconciliation of operating income (loss) to net cash provided by operating activities Operating income (loss)
Adjustments to reconcile operating income (loss) to net cash provided by operating activities Depreciation Decommissioning Advances for capacity and energy Amortization of nuclear fuel Changes in assets and liabilities Accounts receivable Accounts payable and accruals Other Net cash provided by operating activities (117) $
1,324 $
4,024 $
4,238 $
48,887 (6,115) $
45,533 $
18,086 10,900 8,241 19,629 2,220 1,403 (30)
(181) 4,500 10,216 3,113 4,678 4,212 1711 53,834 14,013 2,220 8,241 (2,518) 3,763 (5,153)
(11,950) 11n 9
69 7
234 5,900 (12,769) 59 115 6
3 3
23,556 $
56,981 $
2,175 $
2,519 $
8,768 $
26,386 $
120,385 Cash and cash equivalents as stated in the Combined Statements of Net Assets (Deficit)
Cash/cash equivalents - restricted 5,247 $
36,160 $
179 $
Cash/cash equivalents - unrestricted 1,832 652 829 7.079 $
36,812 $
1.008 $
1,181 $
262 1,443 $
3,007 $
724 3,731 $
4,766 $
19,169 $
24,480 $
94,189 9,752 14,051 14,518 $
19,169 $
24,480 $
108,240 The accompanying notes are an integral part of the combined financial statements.
46
SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY COMBINED STATEMENTS OF CASH FLOWS FOR THE YEAR ENDED JUNE 30, 2004 (Amounts in thousands)
Year Ended June 30, 2004 Southern Palo Transmission Hoover Mead-Mead-Multiple San Magnolia Projects' Verde System Uprating Phoenix Adelanto Project Juan Power Stabilization Project Project Project Project Project Fund Project Project Fund Total Cash flows from operating activities Receipts from participants Payments to operating managers Other receipts Net cash flows from operating activities 174,793 $
87,653 $
(28,055)
(18,976) 153 2,428 $
4,515 $
13,747 $
65,055 $
(43,104)
(254)
(1,275) 159 (2,320) 348,191 (93,984) 312 146,891 68,677 2,174 3,399 11,427 21,951 S -
254,519 Cash flows from noncapital financing activities Withdrawals by participants, net 16 (45,345)
(45,329)
Cash flows from capital financing activities Additions to plant, net (16,681)
(12)
(2,154)
(87,669)
(106,516)
Debt interest payments (32,649)
(41,230)
(1,041)
(4,351)
(13,570)
(14,641)
(10,606)
(12,052)
(130,140)
Proceeds from sale of bonds 44,004 147,064 191,068 Proceeds from escrow restructuring 628 628 Payment for escrow restructuring costs (56)
(56)
Payment for defeasance of revenue bonds (44,061)
(147,259)
(191,320)
Principal payments on debt (49,190)
(29,720)
(1,190)
(7,100)
(8,390)
(95,590)
Transfer of funds from escrow 6,545 6,545 Payment for bond issue costs (220)
(572)
(1,913)
(12)
(2,717)
Net cash used for capital and related financing activities (97,948)
(64,625)
(2,231)
(4,992)
(15,678)
(21,741)
(21,150)
(99,733)
(328,098)
Cash flows from investing activities Interest received on investments 7,469 2,949 49 701 1,853 17,142 1,284 4,076 1,594 37,117 Purchases of investments (360,555)
(42,473)
(2,977)
(784)
(1,877)
(1,271)
(13,264)
(105,005)
(62,942)
(591,148)
Proceeds from sale/maturity of investments 359,456 38,570 500 1,827 5,460 5,870 7,920 46,148 64,707 530,458 Net cash provided by (used for) investing activities 6,370 (954)
(2,428) 1,744 5,436 21,741 (4,060)
(54,781) 3,359 (23,573)
Net increase (decrease) in cash and cash equivalents 55,313 3,098 (2,485) 151 1,185 (3,259)
(154,498) 15.930 162.381 (41,986)
(142,481) 42.941 372.464 Cash/cash equivalents, beginning of year 105,142 37,936 3.726 1.617 2.791 Cash/cash equivalents, end of year 160,455 $
41,034 $
1241 $
176R 3.976 1
12 671 $
7.883 $
955 $
229.983 Reconciliation of operating income to net cash provided by operating activities Operating income Adjustments to reconcile operating income to net cash provided (used) by operating activities Depreciation Decommissioning Advances for capacity and energy Amortization of nuclear fuel Changes in assets and liabilities Accounts receivable Accounts payable and accruals Other Net cash provided by operating activities 101,388 $
39,247 $
223 $
2,209 $
6,955 $
4,031 $
10,209 3,113 17,946 10,900 7,883 19,628 1,404 2,085 4,500 154,053 53,687 14,013 2,085 7,883 2,962 19,941 (105) 174 (1,438) 8,577 11,240 23 (134)
(214) 3 (31) 4,223 503 (128) 146,891 $
68,677 $
2,174 $
3,399 $
11,427 $
21,951 $
254,519 Cash and cash equivalents as stated in the Combined Statements of Net Assets (Deficit)
Cash/cash equivalents - restricted 155,285 $
38,048 $
410 $
Cash/cash equivalents -unrestricted 5,170 2,986 831 160.455 $
41.034 S 1.241 $
1,247 $
521 1.768 $
2,680 $
1,296 3.976 $
7,826 $
7,883 $
955 $
214,334 4,845 15,649 12.671 7.883 $
955 $
229.983 The accompanying notes are an integral part of the combined financial statements, 47
SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY NOTES TO COMBINED FINANCIAL STATEMENTS
- 1.
Organization and Purpose The Southern California Public Power Authority (the "Authority"), a public entity organized under the laws of the State of California, was formed by a joint Powers Agreement dated as of November 1,1980 pur-suant to the Joint Exercise of Powers Act of the State of California. The Authority's participants consist of eleven Southern California cities and one public district of the State of California. The Authority was formed for the purpose of planning, financing, developing, acquiring, constructing, operating and maintaining projects for the generation and transmission of electric energy for sale to its participants. The Joint Powers Agreement has a term of fifty years.
The Authority has interests in the following projects:
Palo Verde Project -
On August 14, 1981, the Authority purchased a 5.91% interest in the PaloVerde Nuclear Generating Station ("PVNGS"),
a 3,810 megawatt nuclear-fueled generating station near Phoenix,Arizona, a 5.56% ownership interest in the Arizona Nuclear Power Project High Voltage Switchyard, and a 6.55% share of the right to use certain portions of the Arizona Nuclear Power Project Valley Transmission System (collec-tively, the "PaloVerde Project"). Units 1,2 and 3 of the PaloVerde Project began commercial operations in January 1986, September 1986, and January 1988, respectively.
Southern Transmission System Project -
On May 1, 1983, the Authority entered into an agreement with the Intermountain Power Agency ("IPA"), to defray all the costs of acquisition and construction of the Southern Transmission System Project ("STS"), which provides for the transmission of energy from the Intermountain Generating Station in Utah to Southern California. STS commenced commercial operations in July 1986. The Department ofWater and Power of the City of Los Angeles
("LADWP"), a member of the Authority, serves as project manager and operating agent of the Intermountain Power Project ("IPP").
Hoover Uprating Project -
As of March 1, 1986, the Authority and six participants entered into an agreement pursuant to which each partic-ipant assigned its entitlement to capacity and associated firm energy to the Authority in return for the Authority's agreement to make advance pay-ments to the United States Bureau of Reclamation ("USBR") on behalf of such participants. The Authority has an 18.68% interest in the contin-gent capacity of the Hoover Uprating Project ("HU").
Mead-Phoenix and Mead-Adelanto Projects -
As of August 4, 1992, the Authority entered into an agreement to acquire an interest in the Mead-Phoenix Project ("Mead-Phoenix"), a transmission line extending between the Westwing substation in Arizona and the Marketplace substa-tion in Nevada. The agreement provides the Authority with an 18.31%
interest in the Westwing-Mead project component, a 17.76% interest in the Mead Substation project component and a 22.41% interest in the Mead-Marketplace project component.
As of August 4, 1992, the Authority also entered into an agreement to acquire a 67.92% interest in the Mead-Adelanto Project ("Mead-Adelanto"), a transmission line extending between the Adelanto substation in Southern California and the Marketplace substation in Nevada.
Funding for these projects was provided by a transfer of funds from the Multiple Project Fund and commercial operations commenced in April 1996. LADWP serves as the operations manager of Mead-Adelanto.
Multiple Project Fund -
During fiscal year 1990, the Authority issued Multiple Project Revenue Bonds for net proceeds of approximately $600 million to provide funds to finance costs of construction and acquisition of ownership interests or capacity rights in one or more, then unspecified, projects for the generation or transmission of electric energy. Certain of these funds were used to finance the Authority's interests in Mead-Phoenix and Mead-Adelanto.
San Juan Project -
Effective July 1, 1993, the Authority purchased a 41.80% interest in Unit 3 and related common facilities of the San Juan Generating Station ("SJGS") from Century Power Corporation. Unit 3, a 497-megawatt unit, is one unit of a four-unit coal-fired power generat-ing station in New Mexico.
Magnolia Power Project -
In March 2003, the Authority received approval from the California Energy Commission for construction of the Magnolia Power Project.The Project consists of a combined cycle natural gas-fired generating plant with a nominally rated net base capacity of 242 megawatts and was built on a site in the City of Burbank, California.The plant is the first that is wholly owned by the Authority and entitlements to 100% of the capacity and energy of the Project have been sold to six of its members. The City of Burbank, a Project participant, is managing its con-struction and operation. Construction is complete and commercial opera-tion is expected to begin in September 2005. During the current year, the Project had no revenues and is not anticipated to have any until the Project becomes operational.
Costs related to the construction of the plant of
$72.2 million and debt service costs of $15.1 million offset by investment income of $1.8 million, were capitalized as part of the utility plant balance.
Once the plant becomes operational, these costs will be recovered through future billings to participants.
Projects' Stabilization Fund -
In fiscal year 1997, the Authority authorized the creation of a Projects' Stabilization Fund. Deposits may be made into the fund from budget under-runs, after authorization of indi-vidual participants, and by direct contributions from the participants.
Participants have discretion over the use of their deposits within SCPPA project purposes. This fund is not a project-related fund; therefore, it is not governed by any project Indenture ofTrust.
Participant Ownership Interests -
The Authority's participants may elect to participate in the projects. As ofJune 30, 2005, the members have the following participation percentages in the Authority's operating projects:
Palo Hoover Mead-Mead-San Magnolia Participants Verde STS Uprating Phoenix Adelanto Juan Power City of Los Angeles 67.0%
59.5%
24.8%
35.7%
City of Anaheim 17.6%
42.6%
24.2%
13.5%
38.0%
City of Riverside 5.4%
10.2%
31.9%
4.0%
13.5%
Imperial Irrigation District 6.5%
51.0%
City of Vernon 4.9%
City of Azusa 1.0%
4.2%
1.0%
2.2%
14.7%
City of Banning 1.0%
2.1%
1.0%
1.3%
9.8%
City of Colton 1.0%
3.2%
1.0%
2.6%
14.7%
4.2%
City of Burbank 4.4%
4.5%
16.0%
15.4%
11.5%
31.0%
City of Glendale 4.4%
2.3%
14.8%
11.1%
9.8%
16.5%
City of Cerritos 4.2%
City of Pasadena 4.4%
5.9%
13.8%
8.6%
6.1%
100.0%
100.0%
100.0%
100.0%
100.0%
100.0%
100%
48
The Authority has entered into power sales and transmission service agree-ments with the above project participants. Under the terms of the con-tracts, the participants are entitled to power output or transmission service, as applicable. The participants are obligated to make payments on a "take or pay" basis for their proportionate share of operating and maintenance expenses and debt service. The contracts cannot be terminated or amend-ed in any manner that will impair or adversely affect the rights of the bondholders as long as any bonds issued by the specific project remain out-standing.
The contracts expire as follows:
Palo Verde Project
.............. 2030 Southern Transmission System Project.......
2027 Hoover Uprating Project............ 2018 Mead-Phoenix Project...........
.. 2030 Mead-Adelanto Project
. 2030 San Juan Project..............
. 2030 Magnolia Power Project...............
2036 The Authority's interests in generation and transmission projects are joint-ly owned with other utilities, except for the Magnolia Project, which is wholly owned by the Authority. Under these arrangements, a participat-ing member has an undivided interest in a utility plant and is responsible for its proportionate share of the costs of construction and operation and it is entitled to its proportionate share of the energy produced. Each joint plant participant, including the Authority, is responsible for financing its share of construction and operating costs. The financial statements reflect the Authority's interest in each joindy owned project as well as the project that it owns. Additionally, the Authority's share of expenses for each pro-ject is included in the statements of revenues, expenses, and changes in net assets (deficit) as part of operations and maintenance expenses.
- 2. Sunoniary of Significant Accounting Policies Basis of Presentation -
The combined financial statement of the Authority are prepared under the accrual basis of accounting in accordance with accounting principles generally accepted in the United States of America. The Authority applies all statements and interpretations issued by the Governmental Accounting Standards Board (GASB) that are applica-ble to governmental entities that use proprietary fund accounting and the Financial Accounting Standards Board (FASB) issued prior to November 30, 1989 that do not conflict with rules issued by the GASB. Revenues are recognized when earned and expenses are recognized when incurred.
The format of the Statement of Net Assets (Deficit) follows the inverted approach which is consistent with the Federal Energy Regnlatory Commission (FERC)."
" Invested in capital assets, net of related debt and deferred cred-its -
This component of net assets consists of (a) capital assets, (b) net of accumulated depreciation and (c) unamortized debt expenses, reduced by the outstanding balances of any bonds, other borrowings and deferred credits that are attributable to the acquisition, construction, or improvement of those assets. If there are significant unspent related debt proceeds at year-end, the portion of the debt attributable to the unspent proceeds is not included in the calculation of invested in capital assets, net of related debt. Rather, that portion of the debt is included in the same net assets component as the unspent proceeds.
" Restricted -
This component consists of net assets on which con-straints are placed as to their use. Constraints include those imposed by creditors (such as through debt covenants), contributors, or laws or reg-ulation of other governments or constraints imposed by law through constitutional provisions or through enabling legislation.
" Unrestricted -
This component of net assets consists of net assets that do not meet the definition of "restricted" or "invested in capital assets, net of related debt and deferred credits."
Use of Estimates -
The preparation of financial statements in confor-mity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of con-tingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.
Utility Plant -
The Authority's share of construction and betterment costs associated with PVNGS, STS, Mead-Phoenix, Mead-Adelanto, SJGS and Magnolia Power Projects are included as utility plant and recorded at cost. Depreciation expense is computed using the straight-line method based on the estimated service lives, principally thirty-five years for PVNGS, STS, Mead-Phoenix and Mead-Adelanto and twenty-one years for SJGS. Magnolia has not commenced commercial operations therefore no depreciation has been recorded.
Balance June 30, 2004 Balance June 30, 2005 Additions Disposals Transfers Nondepreciable utility plant La n d...............................
Construction work in progress...........
Nuclear fuel*........................
Total nondepreciable utility plant......
Depreciable utility plant Production Nuclear generation (Palo Verde Project)
Coal-fired plant (San Juan Unit 3 Project)
Transm ission.........................
G e nera l.............................
Total depreciable utility plant.........
$ 42,451 216,193 14,309 272,953 634,224 171,781 870,022 32,169 1,708,196 21 95,620 6,461 102,102 2,371 2,040 3
35 4,449 (67,847)
(6,118)
(6,118)
(743)
(230)
(8)
(69)
(1,050) 1,047
$ (4 (4,471)
(4,471)
$ 42,472 307,342 14,652 364,466 635,852 173,591 870,017 32,135 1,711,595 (1,089,769)
Less accumulated depreciation........
(1,022,969)
Total utility plant, net............... $ 958,180
- Nuclear fuel disposals represent amortization.
$ 38,704 (6,121)
$ (4,471)
$986,292 49
A summary of changes in Utility Plant follows (amounts in thousands):
Interest expense capitalized to construction work in progress net of capi-talized interest income was $13,467 and $12,662 for the years ended June 30, 2005 and 2004, respectively.
Nuclear Fuel -
Nuclear fuel is amortized and charged to expense on the basis of actual thermal energy produced relative to total thermal ener-gy expected to be produced over the life of the fuel. Under the provisions of the Nuclear Waste Policy Act of 1982, the federal government assesses each entity with nuclear operations, including the participants in PVNGS,
$1 per megawatt hour of nuclear generation. The Authority records this charge as a current year expense. See Note 8 for information about spent nuclear fuel disposal.
Nuclear Decommissioning Decommissioning of PVNGS is expected to commence subsequent to the year 2026. The total cost to decommission the Authority's interest in PVNGS is estimated to be $116.6 million in 2002 dollars ($375.0 million in 2022 dollars, assuming a 6% esti-mated annual inflation rate). This estimate is based on an updated site spe-cific study prepared by an independent consultant in 2001. The Authority is providing for its share of the estimated future decommissioning costs over the remaining life of the nuclear power plant through annual charges to expense, which amounted to $10.9 million in fiscal years 2005 and 2004. The decommissioning liability is included as a component of accu-mulated depreciation and was $192.6 and $181.6 million atJune 30, 2005 and 2004, respectively.
The Authority contributes to external trusts set up in accordance with the Arizona Nuclear Power Plant participation agreement and Nuclear PRegulatory Commission requirements. As of June 30, 2005, decommis-sioning funds totaled approximately $133.1 million, including approxi-mately $1.12 million of interest receivable.
Demolition and Site Reclamation -
Demolition and site reclama-tion of SJGS, which involves restoring the site to a "green" condition, is projected to commence subsequent to the year 2014. Based upon the study performed by an independent engineering firm, the Authority's share of the estimated demolition and site reclamation costs is $30.8 mil-lion in 2003 dollars. The Authority is providing for its share of the esti-mated future demolition costs over the remaining life of the power plant through annual charges to expense of $3.1 million. The demolition liabil-ity is included as a component of accumulated depreciation and totaled
$37.3 million and $34.2 million at June 30, 2005 and 2004, respectively.
As of June 30, 2005, the Authority has not billed participants for the cost of demolition nor has it established a demolition fund.
Investments -
Investments include United States government and gov-ernmental agency securities, guaranteed investment contracts, medium term notes and money market accounts. These investments are reported at fair value and changes in unrealized gains and losses are recorded in the statement of revenues, expenses and changes in net assets (deficit) with the exception of the guaranteed investment contracts which are recorded at amortized cost. Gains and losses realized on the sale of investments are generally determined using the specific identification method.
The Bond Indentures for the seven Projects and the Multiple Project Fund require the use of trust funds to account for the Authority's receipts and disbursements. Cash and investments held in these funds are restricted to specific purposes as stipulated in the Bond Indentures.
Advances for Capacity and Energy -
Advance payments to the United States Bureau of Reclamation for the uprating of the 17 genera-tors at the Hoover Power Plant are included in advances for capacity and energy. These advances are being reduced by the principal portion of the credits on billings to the Authority for energy and capacity.
50 Advance to IPA -Advance to IPA consists of cash transfered to IPA for reserve and contingency and self insurance funding.
Cash and Cash Equivalents -
Cash and cash equivalents include cash and investments with original maturities of 90 days or less.
The Bond Indentures for the seven Projects and the Multiple Project Fund require the use of trust funds to account for the Authority's receipts and disbursements. Cash and investments held in these funds are restricted to specific purposes as stipulated in the Bond Indentures.
Materials and Supplies -
Materials and supplies consist primarily of items for construction and maintenance of plant assets and are stated at the lower of cost or market.
Unamortized Debt Expenses -
Debt premiums, discounts and issue expenses are deferred and amortized to expense over the lives of the relat-ed debt issues. Losses on refunding related to bonds redeemed by refund-ing bonds are amortized over the shorter of the life of the refunding bonds or the remaining term of bonds refunded. Losses on early extinguishment of debt are recognized immediately. Unamortized issue costs are recorded as a noncurrent asset. All other unamortized debt expenses are recorded as an offset or addition to long-term debt.
Arbitrage Rebate and Yield Restrictions -
The unused proceeds from the issuance of tax-exempt debt have been invested in taxable finan-cial instruments. The excess of earnings on investments, if any, over the amount that would have been earned if the investments had a yield equal to the bond yield or yield restricted rate, is payable to the IRS within five years of the date of the bond offering and each consecutive five years thereafter until final maturity of the related bonds.
The recorded liability of the Multiple Project Fund of $17.5 million ($4.7 million payable to the Mead-Phoenix Project and $12.8 million payable to the Mead-Adelanto Project) is a result of the cumulative savings from the 1994 refunding of the 1989 Multiple Project Bonds. The partial refund-ing within five years of the original issuance triggered a recalculation of the arbitrage yield, reducing the Multiple Project Fund's rebate liability.
During the fiscal year ended June 30,2005, the Authority made rebate pay-ments to the IRS of $0.4 million for the STS bonds and $0.9 million for Palo Verde bonds.
R.ecorded arbitrage rebate and yield restriction liabilities as of June 30, 2005, were $0.2 million for Palo Verde, $1.3 million for STS, $0.2 million for Mead-Phoenix, and $0.5 million for Mead-Adelanto.
Revenues -
Revenues consist of billings to participants for the sales of electric energy and transmission service in accordance with the participa-tion agreements. Generally, revenues are fixed at a level to recover all oper-ating and debt service costs over the commercial life of the property.
In September 1998, the PaloVerde participants approved a resolution autho-rizing the Authority to bill the participants an additional $65 million annual-ly through June 30, 2004 to pay for increased debt service costs as a result of a refunding completed in October 1997. In addition, the participants resolved to transfer any over billings, renewal and replacement excess funds or surplus amounts through June 30, 2004 into the Palo Verde reserve account. On November 20, 2003, the Authority adopted a resolution to utilize the amounts on deposit in the reserve accounts to pay a portion of the operating and maintenance expenses of the Palo Verde Project starting July 1, 2004.
Funds held in the reserve account as a result of this resolution totaled $64.2 million and $55.3 million as ofJune 30,2005 and 2004, respectively.
Reclassification -
Certain 2004 balances have been reclassified to con-form to 2005 presentation.
- 3. Investinents The Authority's investment function operates within a legal framework established by Sections 6509.5 and 53600 et. seq. of the California Government Code, Indentures of Trust, instruments governing financial arrangements entered into by the Authority to finance and operate Projects and the Authority's Investment Policy.
Guaranteed investment contracts ("GICs") are contracts that guarantee the owner principal repayment and a specified interest rate for a predeter-mined period of time. GICs are typically issued by insurance companies and marketed to institutions that qualify for favorable tax status under fed-eral laws. These types of securities provide institutions with guaranteed returns. GICs are negotiated on a case-by-case basis.
Based on SCPPA's Investment Policy, certain vehicles such as GICs, flexible repurchase agreements or forward debt service agreements, may be entered into only upon approval of the SCPPA Board. In addition, eligible securi-ties and general limitations are derived from each Project's Indenture of Trust, the Government Code and SCPPA's evolving investment practices.
The operative Indentures ofTrust in which securities are authorized for investment purposes relate to the Palo Verde Project Bonds, the Southern Transmission System Project Bonds, the Hoover Uprating Project Bonds, the Mead-Phoenix Project Bonds, the Mead-Adelanto Project Bonds, the Multiple Project Fund Bonds, the San Juan Project Bonds, and the Magnolia Power Project Bonds. Authorized investments for the Projects' Stabilization Fund are set forth in a resolution approved by the Board in 1996.
Eligible securities include:
" United StatesTreasury Securities, which are bonds or other obligations secured by the fill faith and credit of the United States of America;
" Federal Agency Obligations, which have the full financial backing of the U.S. Government;
" Government Sponsored Enterprise Obligations, which are created by acts of Congress to provide liquidity for selected lending programs tar-geted by Congress;
" Repurchase Agreements, which are collateralized loan contracts where the seller includes a written agreement to repurchase the securities at a later date for a specified amount;
" Negotiable Certificates of Deposit, which are deposit liabilities issued by a nationally or state-chartered bank, a savings or a federal association or by a state-licensed branch of a foreign bank which has a short-term ratings of at least "A-i" by S&P and at least "P-1" by Moody's;
" Banker's Acceptances, a short term draft or bill of exchange guaranteed for payment at face value to the holder of the instrument on its matu-rity date, which has a short-term rating of at least "A-i" by S&P and at least "P-1" by Moody's;
" Commercial Paper, a short-term unsecured promissory note issued by non-financial or financial firms with a rating of at least "A-i" by S&P and at least "P-i" by Moody's;
" Medium Term Notes rated "A" or better and only those issued by cor-porations organized and operating within the United States, or by depository institutions licensed by the United States or any state and operating within the United States;
" Equity-Linked Notes, which are categorized as medium-term corpo-rate notes and are subject to the constraints set forth in the Government code and the Authority's Investment Policy.
Investments at June 30, 2005 and 2004 are as follows:
June 30, 2005 Southern Palo Transmission Hoover Verde System Uprating Proiect Project Project Mead-Mead-Phoenix Adelanto Project Proiect Multiple Project Fund San Magnolia Projects' Juan Power Stabi ization Project Project Fund Total Federal agencies............
U.S. government securities......
Guaranteed investment contracts...
Money market investment account..
Medium term notes Cash.................
Restricted investments........
Unrestricted investments.......
Cash and cash equivalents......
$183,212 68,890 1,058 4,452 88 Total
$ 257,700
$ 164,029 86,592 7,079
$ 41,468 10,544 36,507 1,391 38
$ 89,948
$ 53,136 36,812 4,025 996 8,765 181 435 16 12 4,222
$ 10,208 2,654 8,765 560 1,008 1,443 3,374 24,130 346 11
$ 27,861
$ 24,130 3,731 7,435 226,438
$ 233,873
$ 233,873
$ 23,679 21,323 845 22
$ 45,869
$ 31,351 14,518
$ 50,315 3,696 224 14
$ 54,249
$ 35,080 19,169
$ 53,225 58 20,313
$ 73,596
$ 49,116 24,480
$ 360,294 17,979 389,749 4.538 4.452 20,514
$ 797,526
$ 602,134 87,152 108,240 Total
$257,700
$ 89,948 4,222
$ 10,208
$ 27,861
$233,873
$ 45,869
$ 54,249
$ 73,596
$ 797,526 June 30, 2004 Southern Palo Transmission Hoover Verde System Uprating Project Project Project Mead-Mead-Multiple Phoenix Adelanto Project Proiect Project Fund San Magnolia Pro ects' Juan Power Stabiization Proiect Project Fund Total Federal agencies..........
U.S. government securities....
Guaranteed investment contracts.
Money market investment account Medium term notes Cash................
Restricted investments......
Unrestricted investments.....
Cash and cash equivalents....
$ 338,770 481,729 18,107 4,460 88 Total
$843,154
$ 662,197 20,502 160,455 Total
$ 843,154
$ 49,116 10,354 36,465 1,422 38
$ 97,395
$ 56,361 41,034
$ 97,395 3,922 221 16 4,159 2,358 560 1,241 4,159 1,075 8,709 681 12
$ 10,477 8,709 1,768
$ 10,477 2,970
$ 17,999 7,435 23,893 231,404 21,599 996 (3) 10 20
$ 27,869
$238,839
$ 39,615
$ 23,893
$238,839
$ 26,944 3,976 12,671
$ 27,869
$238,839
$ 39,615
$ 42,154 93,536 602 16
$136,308
$128,425 7,883
$136,308
$ 49,935 548 407
$ 50,890
$ 49,935 955
$ 50,890
$ 505,941 499.518 415,606 22,574 4,460 607
$1,448,706
$1,197,661 21,062 229,983
$1,448,706 51
- 4. Derivative Instrunien ts Objective of the swaps -
In order to protect against the potential of rising interest rates, the Authority has entered into six separate pay-fixed, receive-variable interest rate swaps and one fixed spread basis swap at a cost that is expected to be less over the life of the transaction than what the Authority would have paid to issue fixed-rate debt.
Terms,fair values, and credit risk -
The terms, including the fair values and credit ratings of the counterparties under the outstanding swaps as of June 30, 2005, are included below. In most cases, the notional amount of any swap matches the principal amount of the associated debt. Except as discussed under the rollover risk, the Authority's swap agreements contain scheduled reductions to outstanding notional amounts that are expected to approximately follow scheduled or anticipated reductions in the associated "bonds payable" category.
(Amounts in thousands)
Variable Swap Counterparty Notional Effective Fixed Rate Rate Fair Termination Credit Amount Date Paid Received Values Date Rating MP 2004 Revenue Series A Bonds......................
MA 2004 Revenue Series A Bonds.....................
STS 2004 Fixed Rate Basis Swap.......................
STS 2003 Subordinate Refunding Series A Bonds..........
STS 2001 Subordinate Refunding Series A Bonds..........
STS Sw aption/Swap................................
STS 1991 Revenue Bonds Series A.....................
28,700 96,025 100,000 51,375 79,795 125,000 282,900
$ 763,795 5/27/2004 5/27/2004 12/1/2004 4/24/2003 6/14/2001 2/6/2001 4/17/1991 3.894%
65% of LIBOR (2,977) 3.890%
65% of LIBOR (9,922)
BMA 65% of LIBOR
+ 0.664%
(547) 3.266%
65% of LIBOR (2,059) 4.240% BMA less 40 basis points (8,081) 4.250%
60% of LIBOR (25,655) 6.380% Bond variable coupon rate (76,642)
$ (125,883) 7/1/2020 7/1/2020 7/1/23 7/1/2022 7/1/2021 7/1/2022 6/30/2019 MA+/Aa2 AA+/Aa2 MA-/Aa2 AA-/Aal MA+/Aa2 AA'Aal AA+/Aa2
" STS 2004 Swap -
In November 2004, the Authority entered into a floating-to-floating Fixed-Spread basis swap. Under the swap agree-ment, the Authority will pay a variable rate equal to the BMA index, and in exchange will receive 65% of LIBOR plus a fixed margin or spread of 66.4 basis points. The basis swap is expected to produce net positive cash flow for the Authority given the historical positive differ-ence between the floating rate received and the floating rate paid. The fixed margin of 66.4 basis points represents the fair market or breakeven spread differential prevailing at the time the trade was executed. The swap expires on July 1, 2023.
MIP 2004 Swap -
In connection with the issuance of the 2004 Mead-Phoenix Project Revenue Bonds Series A auction-rate security in May 2004, the Authority entered into an interest rate swap on March 3, 2004. The floating-to-fixed rate swap created synthetic fixed-rate debt for the Authority. Under the Swap Agreement, the Authority pays the counterparty a fixed rate of 3.894% and in exchange the Authority receives a floating rate index equal to 65% of one-month LIBOR. The swap agreement expires July 1, 2020. The Authority received approxi-mately $1.8 million in an upfront payment in connection with the exe-cution of the swap, which has been deferred and is being amortized as an interest yield adjustment over the life of the option. Approximately
$13.5 million in Mead-Phoenix 2004 Project Revenue Bonds Series A are not swapped and remain floating-rate bonds. The floating rate on the related bonds as ofJune 30, 2005 was 2.10%.
" MA 2004 Swap -
In connection with the issuance of the 2004 Mead-Adelanto Revenue Bonds Series A auction-rate security in May 2004, the Authority entered into an interest rate swap on March 3, 2004. The floating-to-fixed rate swap created synthetic fixed-rate debt for the Authority. Under the Swap Agreement, the Authority pays the coun-terparty a fixed rate of 3.89% for the swap and in exchange the Authority receives a floating rate index equal to 65% of one-month LIBOR. The swap agreement expires July 1, 2020. The Authority received approximately $5.9 million in an upfront payment in connec-tion with the execution of the swap, which has been deferred and is being amortized as an interest yield adjustment over the life of the swap.
Approximately $45.1 million in Mead-Adelanto 2004 Project Revenue Bonds Series A are not swapped and remain floating-rate bonds. The average floating rate on the related bonds as ofJune 30,2005 was 2.10%.
" STS 2003 Swap -
In April 2003, the Authority entered into an Interest Rate Swap agreement with a third party for the purpose of hedging against interest rate variations arising from the issuance of the 2003 Subordinate Refunding Series A Southern Transmission Project Revenue Bonds. The notional amount of the Swap Agreement is equal to the par value of the bonds. The Swap Agreement provides for the Authority to make payments to the counterparty on a fixed rate basis of 3.266%, and for the counterparty to make reciprocal payments based on a floating rate of 65% of one-month LIBOR. The floating rate on the related bonds at June 30, 2005 and 2004 was 2.00% and 1.08%,
respectively. The agreement expires on July 1, 2022.
" STS Swaption/Swap -
In February 2001, the Authority entered into a transaction whereby it sold an option (the "Swaption") on a floating-to-fixed interest rate swap. The Swaption was exercised on April 1, 2002. The floating rate on the swap paid by the counterparty is 60% of one-month LIBOR; the annual fixed rate on the swap paid by the Authority is 4.25%. In exchange for the right to exercise the Swaption, the counterparty paid the Authority a one-time up front option premium amount of $7.9 million which has been deferred and is being amortized as an interest yield adjustment over the life of the option. The swap expires on July 1,2022.
" STS 2001 Swap -
In June 2001, the Authority entered into an inter-est rate swap agreement with a counterparty for the purpose of hedg-ing against interest rate variations arising from the issuance of the 2001 Subordinate Refunding Series A Southern Transmission Project Revenue Bonds. The notional amount of the Swap Agreement is equal to the par value of the bonds. The Swap Agreement provides for the Authority to make payments to the counterparty at a fixed rate of 4.24%, and for the counterparty to make reciprocal payments based on a variable rate. The reset dates of the variable rate occur weekly and the rate for a reset date will be the rate determined by the Bond Market Association Municipal Swap Index ("BMA") minus 40 basis points.
The counterparty has the option to cancel the agreement on July 5, 52
2006 and on every Fixed Rate Payer Payment Date, thereafter, should the BMA index average more than 7% over a consecutive 180-day period. The floating rates on the bonds were 2.20% and 1.00% at June 30, 2005 and 2004, respectively. The swap expires on July 1, 2021.
0 STS 1991 Swap -
In fiscal year 1991, the Authority entered into an interest rate swap Agreement with a counterparty for the purpose of hedging against interest rate fluctuations arising from the issuance of the 1991 Subordinate Refunding Series Southern Transmission Project Revenue Bonds. The notional amount of the Swap Agreement is equal to the par value of the bonds.
Under the Swap Agreement, the Authority pays the counterparty a fixed rate of 6.38%; in exchange, the Authority receives payments mirroring the bond variable coupon rate (2.21% and 1.04% at June 30, 2005 and 2004, respectively). The swap expires on June 30, 2019.
Fair value -
All swaps had a negative fair value as ofJune 30, 2005.These fair values take into consideration the prevailing interest rate environment, the specific terms and conditions of a given transaction and any upfront payments that were received. All fair values were estimated using the zero-coupon discounting method. This method calculates the future payments required by the swap, assuming that the current forward rates implied by the yield curve are the market's best estimate of future spot interest rates.
These payments are then discounted using the spot rates implied by the current yield curve for a hypothetical zero-coupon rate bond due on the date of each future net settlement on the swaps. While SCPPA's current market to market values are negative, this valuation would be realized only if the swaps were terminated at the valuation date and only SCPPA retains the right to optionally terminate most of the transactions.
Credit risk -
For each counterparty, the net fair values of the Authority's applicable swaps as ofJune 30,2005 were negative. However, should interest rates change and the fair values of the swaps become positive, the Authority may be exposed to credit risk in the amount of the derivatives' fair value.
The swap agreements contain varying collateral agreements with the counterparties. The swaps require full collateralization of the fair value of the swap should the counterparty's (or guarantors of the counterparty, as applicable) credit rating fall below AA-as issued by Standard & Poor's or Aa3 as issued by Moody's Investors Service for the 1991 Swap;A+/A1 for the 2004 Fixed Spread Basis Swap; A-/A3 for the 2001, the 2003 and the 2004 Swaps; and Baal /BBB+ for the Swaption/Swap. Collateral on all swaps is to be in the form of US government securities held by a third-party custodian.
The swap agreements provide that when the Authority has more than one derivative transaction with a given counterparty involving the same Authority project (and having the same swap/bond insurer),
should one party become insolvent or otherwise default on its obliga-tions, close-out netting provisions permit the non-defaulting party to accelerate and terminate all such related transactions and net the trans-actions' fair values so that a single sum will be owed by, or owed to, the non-defaulting party.
Basis risk -
Basis risk is the risk that the interest rate paid by the Authority on underlying variable rate bonds to bondholders exceeds the variable swap rate received from a counterparty. With the exception of the 1991 Swap, the Authority bears basis risk on each of its swaps. The 1991 Swap is perfectly hedged since the counterparty pays the Authority its actual variable bond rate on the 1991 bonds. All the other Swaps have a basis risk since under each of those swaps the Authority received a per-centage of LIBOR (or BMA less 40 basis points) to offet the actual vari-able bond rate the Authority pays on any related bonds. The Authority is exposed to basis risk should the floating rate that it receives on a swap be less than the actual variable rate the Authority pays on any related bonds or in the case of the floating-to-floating fixed-spread basis swap, less than the variable rate paid to the swap counterparty.
Depending on the magnitude and duration of any basis risk shortfall, the expected cost savings from a swap may not be fully realized. The 2001 swap is based on BMA rate minus 40 basis points; similar to the LIBOR-based swaps, BMA minus 40 bps may not exacdy hedge the underlying variable rate. As ofJune 30,2005, the BMA rate, minus 40 bps, was 2.01%,
whereas 60% of LIBOR was 1.867%, and 65% of LIBOR was 2.022%.
The following is a summary of interest rates paid to and received from the counterparties as ofJune 30, 2005:
Type of Derivative 1991 Swaption/
2001 2003 MA 2004 MP 2004 STS 2004 Swap Swap Swap Swap Swap Swap Swap Payments to counterparty 6.380%
4.250%
4.240%
3.266%
3.890%
3.894%
2.431%
Less, variable payments from counterparty 2.210%
1.867%
2.009%
2.022%
2.022%
2.022%
2.022%
Net interest rate swap payments 4.170%
2.383%
2.231%
1.244%
1.868%
1.872%
0.409%
Add, variable-rate bond coupon payments Synthetic interest rate on bonds 2.210%
N/A 2.200%
2.000%
2.100%
2.100%
N/A 6.380%
2.383%
4.431%
3.244%
3.968%
3.972%
0.409%
Termination risk -
The Authority or the counterparty may terminate any of the swaps if the other party fails to perform under the terms of the contract. In addition, the 2001 Swap provides the counterparty with an option to cancel the swap agreement if the consecutive 180-day averaged rate of the BMA index exceeds 7.0%. However, the cancellation option has a 5-year lockout preventing the swap's termination prior to July 5, 2006. If any of the swaps were terminated, any associated variable rate bonds would no longer be hedged to a fixed rate. If at the time of termi-nation the swap has a negative fair value, the Authority would be liable to the counterparty for a payment equal to the swap's fair value.
Rollover risk -
Rollover risk is the risk that the swap contract is not co-terminus with the related bonds. The Authority is exposed to rollover risk on the 2001 swap because the counterparty has the option to terminate the agreement prior to the maturity of the associated debt. In the event that this swap terminates, the Authority would be exposed to variable interest rates on the underlying bonds. The following debt is exposed to rollover risk:
Associated Debt Issuance Debt Maturity Date Optional Swap Termination Date STS 2001 Subordinate Refunding Series A July 1,2021 July 5, 2006 53
Swap payments and associated debt -
Using rates as ofJune 30, 2005, debt service requirements of the Authority's outstanding variable rate debt and net swap payments are as follows. As rates vary, variable rate bond interest payments and net swap payments will vary.
Fiscal Year Variable-Rate Bonds In accordance with the bond indentures, the new money bonds and refunding bonds are special, limited obligations of the Authority. With the exception of the Magnolia Power Project B, Lease Revenue Bonds (City of Cerritos, California) 2003-1 ("Project B Bonds"), the bonds issued by each project are payable solely from and secured solely by interests in that project as follows:
" Proceeds from the sale of bonds;
" All revenues, incomes, rents and receipts attributable to that project and interest earned on securities held under the bond indenture or indentures; and
" All funds established by the indenture or indentures.
Interest Rate Ending June 30 Principal Interest Swaps, Net 2006 2007 2008 2009 2010 2011 -2015 2016-2020 2021 -2023 1,825 1,950 14,850 15,775 17,275 221,800 325,105 65,215
$ 663,795 14,365 14,323 13,995 13,648 13,267 53,612 20,793 1,104
$ 145,107 19,462 19,394 18,788 18,144 17,447 68,471 24,152 687
$ 186,545 33,827 33,717 32,783 31,792 30,714 122,083 44,945 1,791
$ 331,652 The Authority has agreed to certain covenants with respect to bonded indebtedness, including the requirement to enforce the power and trans-mission sales agreements with the participants. At the option of the Authority, all outstanding new money bonds and refunding bonds are sub-ject to redemption prior to maturity, except for the 1996 Subordinate Refunding Series A Bonds, the 2002 Subordinate Refunding Series B Bonds, and portions of the 1988A Refunding and 1992 Subordinate Refunding Bonds issued for the Southern Transmission System; the 2002A San Juan Revenue Bonds; and a total of $125.5 million of the Multiple Project Revenue Bonds.
Variable rate debt includes Auction Rate Certificates ("ARCs"), which bear interest at the applicable auction rate as determined by an Auction Agent, as well as debt with rates based on daily, weekly and long term rates as determined by a Remarketing Agent.
- 5. Long-Term Debt Long-term debt outstanding at June 30, 2005 consisted of"new money" bonds, refunding bonds and subordinate refunding bonds due in varying annual amounts through 2036. The new money bonds were issued to finance the purchase and construction or acquisition of the Authority's interest in each of the Projects. The subordinate refunding bonds were issued to refund specified new money bonds.
A summary of changes in long-term debt follows:
(Amounts in thousands)
Southern Transmission Hoover Mead-Mead-Multiple Magnolia Projects' Palo Verde System Uprating Phoenix Adelanto Project San Juan Power Stabilization Project Project Project Project Project Fund Project Project Fund Total Total long-term debt at June 30, 2004 569,050 $
795,222 $
18,575 $
65,463 $
210,861 $
209,524 $
191,277 $
321,327 $
$ 2,381,299 Total debt due within one year at June 30, 2004 Total debt at June 30, 2004 Principal payments Revenue bonds issued Bonds refunded/defeased Refunding bonds issued Decrease in unamortized debt-related costs, net Total debt at June 30, 2005 Total debt due within one year at June 30, 2005 Total long-term debt at June 30, 2005 51,800 28,535 1,230 7,600 8,805 97,970 620,850 823,757 19,805 65,463 210,861 217,124 200,082 321,327 2,479,269 (63,680)
(28,535)
(1,230)
(7,600)
(8,805)
(109,850) 71,880 71,880 (512,025)
(71,850)
(583,875) 73,862 14,136 416 471 1,294 680 (688)
(418) 89,753 119,007 809,358 18,991 65,934 212,155 210,204 190,619 320,909 1,947,177 (11,300)
(31,470)
(1,275)
(8,100)
(9,160)
(61,305) 107,707 $
777,888 $
17,716 $
65,934 $
212,155 $
202,104 $
181,459 $
320,909 $
$ 1,885,872 PaloVerde Project -
Debt consists of subordinate refunding series bonds with variable interest rates and final maturities between 2009 and 2017.
Bonds Redeemed -
In 1997, the Authority began taking steps designed to accelerate the payment schedule of all fixed rate subordinate bonds relat-ing to the Palo Verde Nuclear Generating Station (PVNGS) so that they would be paid off byJuly 1,2004 (the "Restructuring Plan"). Certain out-standing bonds were refunded for savings and the project participants accelerated payments on the bonds issued by the Authority for PVNGS.
Accelerated payments were approximately $65 million per year from 1997 until final payment on July 1, 2004. The Plan resulted in substantial sav-ings to the PVNGS project participants once the principal and interest on these fixed rate subordinate bonds were paid in full.
As part of the Restructuring Plan, $512 million of debt was placed into legal defeasance as ofJuly 1, 2004.
Southern Transmission System Project -
Debt consists of refunding and subordinate refunding series bonds with fixed and variable interest rates. Fixed interest rates range from 3% to 6.125% and final maturities occur between 2006 and 2023.
Hoover Uprating Project -
Debt consists of refunding series bonds with fixed interest rates between 3.5% and 5.25% and a final maturity during 2017.
Mead Phoenix Project -
Debt consists of revenue and refunding series bonds with variable interest rates and a 5.15% fixed interest rate. Final maturity occurs during 2020.
Bonds Refunded -
On May 27, 2004, the Authority issued $42.2 million of the Mead-Phoenix refunding bonds (the "2004 Refunding Bonds") to refund $42.2 million of Mead-Phoenix 1994 Series A Bonds. This trans-54
action resulted in a net loss for accounting purposes of $6.6 million, con-sisting primarily of the write-off of unamortized debt expense and the dis-count associated with the Refunded Bonds. The Authority has propor-tionally allocated this loss between bonds refunded through funds released from debt service accounts and funds received from the issuance of refund-ing bonds. The loss allocated to the issuance of refunding bonds of $6.5 million was deferred and will be amortized in accordance with GASB 23 over the remaining life of the old debt or the life of the new debt, whichever is shorter. The portion refunded with cash resulted in immedi-ate recognition of a $127,000 loss in fiscal year 2004.
Mead Adelanto Project -
Debt consists of revenue and refunding series bonds with variable interest rates and a 5.15% fixed interest rate. Final maturity occurs during 2020.
Bonds Refunded -
On May 27, 2004, the Authority issued $141.2 million of the 2004 Mead-Adelanto refunding bonds (the "2004 Refunding Bonds") to refund $141.2 million of Mead-Adelanto 1994 Series A Bonds.
This transaction resulted in a net loss for accounting purposes of $19.8 mil-lion, consisting primarily of the write-off of unamortized debt expense and the discount associated with the Refunded Bonds. The Authority has pro-portionally allocated this loss between bonds refunded through funds released from debt service accounts and through funds received from the issuance of refunding bonds. The loss allocated to the new bonds of $19.4 million was deferred and will be amortized in accordance with GASB 23 over the remaining life of the old debt or the life of the new debt, whichever is shorter. The portion refunded with cash resulted in immedi-ate recognition of a $149,700 loss in fiscal year 2004.
Multiple Project Fund -
Debt consists of revenue bonds with fixed inter-est rates ranging between 5.5% and 7.0% and final maturity during 2020.
Bonds Redeemed -
On January 4, 1990, the Authority issued its Multiple Project Revenue Bonds, 1989 Series. Most of the proceeds of the Bonds were used to fund Authority projects, specifically the Mead-Phoenix and the Mead-Adelanto Transmission Projects. In April 2005, the Board deter-mined that a portion of the remaining available proceeds should be used to redeem the callable bonds.
In May 2005, the Authority's Board of Directors approved the redemption of $162.1 million Multiple Projects Revenue Bonds, 1989 Series, representing all of the callable bonds. The bonds were redeemed on July 1, 2005.
San Juan Project -
Debt consists of refunding series bonds with fixed interest rates between 4.5% and 5.5% and final maturities during 2014 and 2020.
San Juan Unit 3 Project Refunding -
In April 2005, the Authority issued
$71.88 million par value SJ 2005 Refunding Series A Bonds to refund all of the outstanding $71.85 million SJ 2002 Refunding Series B Bonds (the "refunded bonds"). This transaction resulted in a net loss for accounting purposes of $4.4 million, consisting primarily of the write-off of unamor-tized debt expenses and the premium associated with the refunded bonds.
The loss on refunding of bonds was deferred and will be amortized in accordance with GASB 23 over the remaining life of the old debt or the life of the new debt, whichever is shorter.
San Juan completed the advanced refunding to reduce its total debt service payments over the refunding term by $9.9 million and to obtain an eco-nomic gain, measured as the difference between the present values of the old and new debt service payment requirements of $6.6 million.
Magnolia Project -
Debt consists of revenue bonds with fixed interest rates between 2.00% and 5.25% with final maturities between 2020 and 2036.
Of the outstanding bonds, $14.1 million of "Project B Bonds" are secured by lease rental payments to be made by the City of Cerritos (the "City")
in connection with the lease of certain facilities and premises owned by the City to the Authority and the leaseback of such facilities and premises to the City. The Base Rental Payments will be equal to the principal and interest on the Project B Bonds.
In accordance with the Assignment Agreement between the Authority and the Trustee, the Authority will assign certain of its rights under the Lease, including its right to receive the Base Rental Payments, to the Trustee for the benefit of the Owners of the Project B Bonds.
The City has covenanted to budget and appropriate sufficient funds to make all payments required to be made under the Lease. The Lease has a term of 55 years.
Debt Related Costs -
Unamortized debt-related costs, net are as follows as ofJune 30, 2005 (amounts in thousands):
Loss on (Premium)
Unamortized debt-related costs, net Refunding Discount Total Palo Verde Project................................................
Southern Transmission System Project................................
Hoover Uprating Project............................................
M ead-Phoenix Project.............................................
M ead-Adelanto Project............................................
M ultiple Project Fund..............................................
San Juan Project.................................................
M agnolia Pow er Project............................................
Debt Service -
The scheduled debt service payments for future years endingJune 30 are included in the following table. The variable rates used for the PV 1996 Subordinate PRefunding Series B and C, and the STS 1996 Subordinate Refunding Series B were the rates at June 30, 2005 of 2.21%
and 2.22%, respectively. The variable rates are set by the bond-remarket-ing agent on a weekly basis based on economic conditions and bond rat-ings.The variable rate used for the SJ 2002 Revenue Refunding Series B was assumed at 4% per annum starting in January 1, 2012.
17,553 106,339 2,692 6,534 19,434 8,241 160,793 24,122 (324)
(563)
(2,419) 10,196 (12,216)
(6,829) 11,967 17,553 130,461 2,368 5,971 17,015 10,196 (3,975)
(6,829)
$ 172,760 55
(Amounts in thousands)
Southern Transmission Hoover Palo Verde System Uprating Project Project Project Mead-Mead-Multiple Phoenix Adelanto Project Project Project Fund Magnolia San Juan Power Project Project Total 2006 Principal.................
11,300 Interest.................
4,069 2007 Principal.................
11,545 Interest.................
3,729 2008 Principal.................
11,895 Interest.................
3,382 2009 Principal.................
12,250 Interest...
3,024 2010 Principal.................
10,075 Interest.................
2,662 2011-2015 Principal...
55,075 Interest.................
8,581
$ 31,470 36,844 34,230 36,279 30,950 34,668 31,550 32,909 30,880 31,168 220,715 125,514 1,275 943 1,315 893 1,370 838 1,425 782 1,480 723 8,400 2,553 6,094 411 3,306 3,250 3,224 3,350 3,141 3,425 3,055 3,500 2,967 24,680 9,965 27,500 3,439 6,200 10,280 10,850 10,009 11,150 9,730 11,400 9,445 11,725 9,152 71,220 32,187 92,050 11,500 20,775 8,100 13,297 13,297 13,297 13,297 38,500 10,602 50,200 41,421 83,100 26,095 40,500 9,160 9,453 9,570 9,008 10,050 8,517 10,550 7,982 11,115 7,400 77,520 25,985 15,170 3,735 15,096 4,520 15,005 4,610 14,896 4,720 14,735 26,595 70,283 61,305 93,362 74,495 91,535 73,285 88,578 75,210 85,390 111,995 79,409 534,405 316,489 607,503 182,095 388,629 62,291 55,020 40,293 70,220 24,331 67,870 2,583 2016-2020 Principal.................
Interest.................
2021-2025 Principal.................
Interest.................
2026-2030 Principal.................
Interest.................
2031-2035 Principal.................
Interest.................
2036-2037 Principal.................
Interest.................
Principal.................
Interest.................
24,420 282,005 1,044 70,383 278,019 9,503 58,679 33,655 6,545 62,678 43,135 52,788 55,020 40,293 70,220 24,331 67,870 2,583
$ 136,560
$ 939,819 21,359 71,905
$ 229,170
$ 220,400
$ 186,644
$ 314,080
$2,119,937 26,491
$ 377,268 7,143 29,097 92,303
$ 131,306 74,890
$ 327,858
$1,066,356 Fair Value -
The fair value of the Authority's long-term debt (including the current portion) is approximately $2.2 billion and $2.8 billion at June 30,2005 and 2004, respectively. Management has estimated fair value based on the quoted market prices for the same or similar issues or on the cur-rent average rates offered to the Authority for debt of approximately the same remaining maturities, excluding the effect of a related interest rate swap agreement.
Advance Refundings -
The Authority has established irrevocable escrow trusts with the proceeds from issuance of subordinate refunding bonds. These investments will be used to pay specified revenue bonds called at scheduled redemption dates.
Defeasance of Debt -
The Authority has defeased specified revenue bonds by placing the proceeds from the issuance of subordinate refunding bonds in irrevocable trusts to provide for all future debt service payments on the refunded bonds. The trust investments and related liability for bonds that are considered legally defeased are not included in the Authority's financial statements. At June 30, 2005 and 2004, $728.3 mil-lion and $334.4 million, respectively, of revenue bonds outstanding are considered legally defeased.
The refunded bonds constitute a contingent liability of the Authority only to the extent that cash and investments presently in the control of the refunding trustees are not sufficient to meet debt service requirements, and are therefore excluded from the combined financial statements because the likelihood of additional funding requirements is considered remote.
- 6. Notes Payable Notes payable consists of participant over billings from prior periods to be paid through June 2017. The notes are unsecured, bear an interest rate of 4.97% and are due in monthly payments of $636.
- 7. Net Assets (Deficit)
The Authority's billing amounts to the participants are determined by its Board of Directors and are subject to review and approval by the partici-pants. Billings to participants are designed to recover "costs" as defined by the power sales and transmission service agreements. The billings are struc-tured to systematically provide for debt service requirements, operating funds and reserves in accordance with these agreements. The accumulat-ed difference between billings and the Authority's expenses calculated in accordance with accounting principles generally accepted in the United States ofAmerica are presented as net assets (deficit). It is intended that this difference will be recovered in the future through billings for repayment of principal on the related bonds.
56
Net assets (deficit) are comprised of the following (in thousands):
(Amounts in thousands)
June 30, Fiscal Year June 30, Fiscal Year June 30, 2003 2004 Activity 2004 2005 Activity 2005 GAAP items not included in billings to participants Depreciation of plant.................................
$ (814,38 Nuclear fuel amortization..............................
(19,54 Decommissioning expense.............................
(131,25 Amortization of bond discount, debt issue costs, and loss on refundings.....................
(584,45 Interest expense.....................................
(62,27 Loss on defeasance of bonds...........................
Bond requirements included in billings to participants Operations and maintenance, net of investment income......
274,90 Costs of acquisition of capacity.........................
19,92 Billings to amortize costs recoverable....................
331,64 Reduction in debt service billings due to transfer of excess funds....................................
(90,02 Principal repaym ents.................................
780,31 O ther..............................................
65,63 (229,52 M ultiple Project Fund net assets..........................
6,69 Projects' Stabilization Fund net assets......................
96,42
$(126,41
- 8. Commitments and Contingencies Deregulation -
Since the passage of Assembly Bill 1890 (the "Bill") in September 1996, the electric industry in California has been through try-ing times; blackouts, investor-owned utility retail rate hikes of 30%, bank-ruptcies of investor-owned utilities and power marketers, and incurrence of tremendous debt financings by the State of California. Uncertainty still exists regarding the construction of new power generation and transmis-sion facilities.The public power systems in the Authority were not required to comply with the Bill's provisions, continued to plan for the needs of their customers and was not faced with customers choosing direct access and leaving the system. Most of the Authority's members have invested in new gas-fired peaking or base-load generation located in Southern California. The new SCPPA-owned 310 Megawatt gas-fired combined cycle Magnolia Power Project in Burbank is an example of the Authority members' commitment to make the necessary investment to provide for their customers' needs. The recent acquisition of underground natural gas supplies in the Pinedale region ofWyoming to provide stable fuel supplies for this local generation is another example of prudent planning by the Authority members. The members continue to collect the public benefit charge, and to date have instituted in excess of $500 million of programs to benefit their customers. The local governing authority decides how the funds (approximately 2.5% of gross revenues) will be spent in the areas of renewable resources, conservation, research and development, and low-income rate subsidies.
Commitments for renewable energy supplies already include wind, geothermal, landfill, gas and photovoltaics. The Authority cannot predict the impact of any future direct access or dereg-ulation programs on energy markets or its participants.
Nuclear Spent Fuel and Waste Disposal -
Under the Nuclear Waste Policy Act, the Department of Energy ("DOE") was to develop the facil-ities necessary for the storage and disposal of spent fuel and to have the first such facility in operation by 1998. That facility was to be a permanent
$ (53,687)
(6,009)
(31,294)
(7,371) 9,227 (1,224) 50,410 82,203 3,579 45,834 415 (44,966)
$1,283
$ (868,073)
(19,548)
(137,264)
(615,750)
(69,648) 284,132 18,698 382,050 (90,020) 862,521 69,209 (183,693) 7,107 51,455
$(125,131)
$ (53,834)
(14,013)
(19,578)
(1,428)
(85,827)
$ (921,907)
(19,548)
(151,277)
(635,328)
(71,076) 9,007 293,139 (1,264) 17,434 382,050 49,397 (13,511)
(131,051) 493 22,658
$(107,900)
(90,020) 911,918 55,698 (314,744) 7,600 74,113
$(233,031) repository, but the DOE has announced that such a repository could not be completed before 2010.There is ongoing litigation with respect to the DOE's ability to accept spent nuclear fuel and no permanent resolution has been reached to date.
In July 2002, a measure was signed into law designating the Yucca Mountain in the state of Nevada as the nation's high-level nuclear waste repository. This meant that the DOE could then file a construction and operation plan for Yucca Mountain with the Nuclear Regnlatory Commission ("NRC"). The DOE expected that theYucca Mountain site would be open by 2010. However, the State of Nevada and its congres-sional delegation are still determined to halt the project through the NRC process or through legal challenges.
Nuclear Spent Fuel and Waste Disposal (Continued) -
Also a feud over funding of the repository ensued.
The Administration and Congressional leaders pushed for full and adequate funding, in order for the DOE to meet the application deadline of 2004.
Meanwhile, the Nevada delegation worked diligently to delay the DOE's work on the license application for the Yucca site, in hopes of halting the transfer of nuclear waste to the Nevada facility. As of today, a license application for a repository atYucca Mountain has still not been submitted.
The spent fuel storage in the wet pool at PVNGS exhausted its capacity in 2003.
A Dry Cask Storage Facility (the "Facility"), also called the Independent Spent Fuel Storage Facility, was built and completed in 2003 at a total cost of $33.9 million (about $2 million for the Authority). In addition to the Facility, the costs also account for heavy lift equipment inside the units and at the yard, railroad track, tractors, transporter, transport canister, and surveillance equipment. The Facility has the capacity to store all the spent fuel generated by the PVNGS plant until 2026. To date, over 30 casks, each containing 24 spent fuel assemblies were placed in the 57
Facility. The current plan calls for the removal of between 240 and 288 fuel assemblies from the units to the Facility every year. The costs incurred by the procurement, packing, preparation and transportation of the casks are included as part of the fuel expenses, and will cost approximately $13 million a year (about $760,000 for the Authority). If the permanent repos-itory in Yucca Mountain is opened as scheduled in 2010, the spent fuel from PVNGS will be shipped to the repository starting in 2031. No pro-vision has been included in the accompanying financial statements.
Nuclear Insurance -
The Price-Anderson Act (the "Act") requires that all utilities with nuclear generating facilities share in payment for claims resulting from a nuclear incident. The Act limits liability from third-party claims to approximately $10.8 billion per incident. Participants in the Palo Verde Nuclear Generating Station currently insure potential claims and lia-bility through commercial insurance with a $300 million limit; the remain-der of the potential liability is covered by the industry-wide retrospective assessment program provided under the Act. This program limits assess-ments to $101 million per reactor for each licensee for each nuclear inci-dent occurring at any nuclear reactor in the United States; payments under the program are limited to $15 million per reactor, per incident, per year.
Based on the Authority's 5.91% interest in PaloVerde, the Authority would be responsible for a maximum assessment of $17.8 million, limited to pay-ments of $1.8 million per incident, per year.
Other Legal Matters -
With respect to the San Juan Generating Station (including the Authority's ownership interest in Unit 3 thereof), the Sierra Club and the Grand Canyon Trust have filed suit against Public Service Company of New Mexico ("PNM") in federal court alleging vio-lations of the Clean Air Act and of the conditions of the San Juan Generating Station's operating permit. PNM is a co-owner of the San Juan Generating Station and is the operating agent of the station. The law-suit sought penalties as well as injunctive and declaratory relief.
During 2005, the parties achieved a settlement of the substantive elements of the case which has been approved by the United States District Court.
A number of environmental upgrades are being made to the San Juan Generating Station that is expected to mitigate a number of environmen-tal consequences which might otherwise occur in the operation of the plant. The additional costs associated with these environmental upgrades will be shared by the San Juan Generation Station participants. The envi-ronmental upgrades affecting Unit 3 and the SCPPA San Juan participants are not anticipated to be added until approximately 2008. A current esti-mate which would be borne by the SCPPA San Juan Generating Station participants ranges from $13 to $16 million. SCPPA has already budgeted for the portion of the added costs of these upgrades which the SCPPA par-ticipants will bear. The upgrade expenditures of Unit 3 are not anticipat-ed to occur until Spring 2008, and SCPPA is currently incorporating these costs into current and future budget projects. A liability has been estab-lished for $16 million and is presented as a deferred credit. The corre-sponding asset has been recorded as a deferred debit less cash already received from the participants.
Claims and a lawsuit for damages have been filed with the Authority, Intermountain Power Authority (the "IPA") and the LADWP seeking
$100 million in special damages and a like amount in general damages.
The claimants allege, among other things, that due to improper grounding of the transmission line of STS, their dairy herds were damaged and the value of their land was diminished. The claimants also seek injunctive relief. The Authority believed these claims were substantially without merit as to itself because the Authority has no ownership or operational control over the subject transmission lines, and merely acted as a financing agency with respect to STS. In July 2003, the Authority, IPA, and LADWP filed a motion to dismiss, or in the alternative, a motion to stay based upon forum non conveniens, in which the defendants argued that the case had little connection with California and should be heard in Utah. The Los Angeles Superior Court granted the motion and in a 2004 unpublished opinion the California Court ofAppeal affirmed this matter on appeal. A Petition for Review was subsequently denied by the California Supreme Court.
In February 2005, the remaining Utah plaintiffs filed a complaint in the Third Judicial District Court in and for Salt Lake County, Utah, which alleged facts similar to those alleged in California. SCPPA has moved the Utah court to dismiss the action as to SCPPA; however, the motion has not yet come on for hearing before the Court. The motion to dismiss is cur-rently stayed pending the determination for the Utah trial court whether to transfer the action from Salt Lake County to the District Court in Millard County Utah, where the Intermountain Power Project is located.
No provision has been included in the accompanying financial statements.
The Authority is also involved in various other legal actions. In the opin-ion of management, the outcome of such litigation or claims will not have a material effect on the financial position or the results of operations of the Authority or the respective separate Projects.
- 9. Subsequent Events -
Natural Gas Reserve Acquisition Project The acquisition of natural gas leases in Pinedale, Wyoming and other real property from Anschutz Corporation of Denver, Colorado was successful-ly completed on July 1, 2005. The transaction totaled in excess of $300 million for LADWP (74.4681%), Turlock Irrigation District (10.6383%),
Anaheim (5.3191%), Glendale (4.2553%), Burbank (2.1277%) Pasadena (2.1277%), and Colton (1.0638%). Gas began to flow to the participants at 12:01 a.m. on July 1,2005.
The financing consisted of taxable draw down bonds with a principal amount not to exceed $100,000,000 at an interest rate of the one month LIBOR rate plus fifty basis points. As of July 1, 2005, the Authority had drawn down approximately $26 million on the bonds. The bonds were issued on behalf of Anaheim (52.6%), Burbank (10.5%) and Colton (36.9%) to finance their share of the project.
The Project will be structured on the same method as the other Projects.
Participants will be billed for operating costs, debt service and capital expenditures.
58
SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY SUPPLEMENTAL FINANCIAL INFORMATION INDEX Palo Verde Project
-° Supplemental Schedule oftReceipts and Disbursements in Funds Required by the Bond Indenture for theYear Ended June 30, 2005 Southern Transniission System Project Supplemental Schedule of Receipts and Disbursements in Funds Required by the Bond Indenture for the Year Ended June 30, 2005 Hoover Uprating Project 0
, c Supplemental Schedule oflReceipts and Disbursements in Funds Required by the Bond Indenture for theYear Ended June 30, 2005 Mead-Phoenix Project Supplemental Schedule of Receipts and Disbursements in Funds Required by the Bond Indenture for theYear Ended June 30, 2005 Mead-Adelanto Project Supplemental Schedule of Receipts and Disbursements in Funds Required by the Bond Indenture for theYear Ended June 30, 2005 Multiple Project Fund Supplemental Schedule oflReceipts and Disbursements in Funds Required by the Bond Indenture for the Year Ended June 30, 2005 San Juan Project Supplemental Schedule of Receipts and Disbursements in Funds Required by the Bond Indenture for the Year Ended June 30, 2005 Magnolia Power Project Supplemental Schedule of Receipts and Disbursements in Funds Required by the Bond Indenture for the Year Ended June 30, 2005 59
SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY PALO VERDE PROJECT SUPPLEMENTAL SCHEDULE OF RECEIPTS AND DISBURSEMENTS IN FUNDS REOUIRED BY THE BOND INDENTURE FOR THE YEAR ENDED JUNE 30, 2005 (Amounts in thousands)
Debt Debt Service Service Reserve Fund Fund Decom-missioning Trust Deposit Fund Installment Deposit Reserve Escrow Installment Account General Reserve Issue Account Account Operating Reserve & Revenue Account Contingency Fund Total Balance at June 30, 2004................. $ 30,254 Additions Investment earnings...................
120 Discount on investment purchases........
13 Distribution of investment earnings.......
(132)
Revenue from power sales..............
Distribution of revenue.................
76 Transfer from escrow fund for principal and.
interest payments...................
1,604 Other...............................
(13) t~1~
~17R~7n
~
PiER
~
PP7 PNRR23 t
44nflfl
~ 7R1R7
~ q22?E
~
P47 ~7R7¶~7
$ 34513
$128373
$ 6168 $
997 $ 398 623 $
$ 44500
$ 26 167 $ 92 225 $
542
$762362 1
35 (36) 4,780 24 (1
9,344 6,393 2,808 84 275 (318) 10,923 4,034 85 (577) 26,043 632 125 (757) 12,689 61 1,821 49,439 (52,539) 19,001 6,952 49,439 (34,489)
(29,786) 28,182 (6,161)
(1,000) 43,824 (2,808)
(3,344) 71,777 (68,446) 01362 (55.7571 730 70 (5421 75.462 Tota l............................
1.668 134.4819 4.804 f6.161)
(.000) 29.775 35.802 1
Deductions Construction expenditures...............
Operating expenditures.................
Remarketing/commitment fees...........
Fuel costs...........................
Payment of principal...................
Interest paid - non escrow..............
Premium and interest paid on investment purchases..............
Payment of principal and interest paid escrow...............
~
~3.
24,250 2,064 471 39,430 3,241 30,269 8,706 11,482 11,482 30,272 471 8,706 63,680 5,305 80 80 1.605 28.182 29.787 Total............................
27,919 83 71.324 38.975 11.482 149.783 Balance at June 30, 2005............... $ 4,003 24
$133.094 $
7 $
(3) $428,398 $
- $ 8.978
$ 88.554 $ 24,986 $
$688,041 This schedule summarizes the receipts and disbursements in funds required under the Bond Indenture and have been prepared from the trust statements. The balances in the funds consist of cash and investments at original cost for both on balance sheet funds and off balance sheet escrows for legally defeased debt. These balances do not include accrued interest receivable, unrealized gain (loss) on investment and $88 held in the revolving fund at June 30, 2005 and 2004.
60
SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY SOUTHERN TRANSMISSION SYSTEM PROJECT SUPPLEMENTAL SCHEDULE OF RECEIPTS AND DISBURSEMENTS IN FUNDS REQUIRED BY THE BOND INDENTURE FOR THE YEAR ENDED JUNE 30, 2005 (Amounts in thousands)
Debt Service Fund Escrow Fund Issue Fund Operating Fund Revenue Fund Total Balance at June 30, 2004................................................
Additions Investm ent earnings...................................................
Discount on investm ent purchases.......................................
Distribution of investm ent earnings.......................................
Revenue from transm ission sales........................................
D istribution of revenue.................................................
Transfer from escrow fund required by refunding bonds issuance.............................................
O ther transfers.......................................................
T o ta l.............................................................
Deductions O perating expenses...................................................
Paym ent of principal...................................................
Interest and arbitrage paid..............................................
Principal and interest paid on escrow bonds................................
T o ta l.............................................................
Balance at June 30, 2005................................................
11,148 14,687 72,367 2,947
$ 101,149 1
1,866 2,851 3
11 4,732 30 425 38 31 524 (31)
(3,276)
(41) 3,348 71,742 71,742 4,592 57,720 12,820 (75,132)
(6,580) 6,580 (54) 54 4,592 (4,768) 64,354 12,820 76,998 15,153 15,153 11,085 17,450 28,535 39,195 39,195 6,580 6,580 11,085 63,225 15,153 89,463 4,655 9,919 73,496 614 88,684 This schedule summarizes the receipts and disbursements in funds required under the Bond Indenture and have been prepared from the trust statements. The balances in the funds consist of cash and investments at original cost. These balances do not include accrued interest receivable, unrealized gain (loss) on investment and $38 held in the revolving fund at June 30, 2005 and 2004.
61
SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY HOOVER UPRATING PROJECT SUPPLEMENTAL SCHEDULE OF RECEIPTS AND DISBURSEMENTS IN FUNDS REQUIRED BY THE BOND INDENTURE FOR THE YEAR ENDED JUNE 30, 2005 (Amounts in thousands)
Debt General Service Reserve Fund Fund 924 1,700 Advance Payment Fund I
Operating Fund 3
1,368 Revenue Fund Total 206 4.201 Balance at June 30, 2004.................................................
Additions Investm ent earnings....................................................
Discount on investment purchases........................................
Distribution of investm ent earnings........................................
Revenue from pow er sales..............................................
D istribution of revenue..................................................
T o ta l..............................................................
Deductions Operating expenses....................................................
Paym ent of principal...................................................
Interest paid.........................................................
To ta l..............................................................
51 (51) 31 5
(36)
O'n 97 2,401 07 af~
89 9
2,401 L,' /
LU L, IUi 2,475 230 (206) 2,499 226 226 1,230 1,230 998 998 2,228 226 2,454 Balance at June 30, 2005.................................................
1,171 1.700 3
1.372 4,246 This schedule summarizes the receipts and disbursements in funds required under the Bond Indenture and have been prepared from the trust statements. The balances in the funds consist of cash and investments at original cost. These balances do not include accrued interest receivable, unrealized gain (loss) on investment and $16 held in the revolving fund at June 30, 2005 and 2004.
62
SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY MEAD-PHOENIX PROJECT SUPPLEMENTAL SCHEDULE OF RECEIPTS AND DISBURSEMENTS IN FUNDS REQUIRED BY THE BOND INDENTURE FOR THE YEAR ENDED JUNE 30, 2005 (Amounts in thousands)
Debt Debt Service Revenue Service Reserve Fund Account Account Reserve &
Operating Contingency Fund Fund Surplus Fund Cost of Issuance Fund Escrow Account Total Balance at June 30, 2004............... $
Additions Investment earnings..................
2 Discount on investment earnings........
Distribution of investment earnings......
105 Transmission revenue.................
3,707 Distribution of revenues...............
(3,930)
Payments from Western Area Power Administration...............
116 Other transfers......................
Total............................
Deductions Construction expenditures.............
Operating expenses..................
Principal payment....................
Premium and interest paid on defeased bonds Debt issuance costs..................
Interest paid........................
Total............................
2,769 5,915 451 1,271 58 44,061 54,525 121 9
435 2,495 435 2
105 1
38 704 (435)
(1 1,101 9
105) 3,707 25 309 116 (9) 9 3,069 1,103 25 310 (9) 38 4,536 65 1,304 42,235 1,864 49 65 1,304 42,235 1,864 49 3,349 3,349 3,349 1,304 65 49 44,099 48,866 2,489 5,915 250 1,231 310 10,195 Balance at June 30, 2005............... $
This schedule summarizes the receipts and disbursements in funds required under the Bond Indenture and have been prepared from the trust statements. The balances in the funds consist of cash and investments at original cost. These balances do not include accrued interest receivable, unrealized gain (loss) on investment, and $12 held in the revolving fund at both June 30, 2005 and 2004.
63
SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY MEAD-ADELANTO PROJECT SUPPLEMENTAL SCHEDULE OF RECEIPTS AND DISBURSEMENTS IN FUNDS REQUIRED BY THE BOND INDENTURE FOR THE YEAR ENDED JUNE 30, 2005 (Amounts in thousands)
Debt Service Account Debt Service Reserve Account Reserve &
Operating Contingency Revenue Fund Fund Fund Surplus Escrow Fund Account Cost of Issuance Fund Total Balance at June 30, 2004...................................
Additions Investm ent earnings.....................................
Discount on investment earnings...........................
Distribution of investment earnings.........................
Transm ission revenue....................................
Distribution of revenues..................................
Payment from Western Area Power Administration.............
Other transfers.........................................
Total................................................
Deductions Principal paym ent.......................................
Interest paid..........................................
Debt issuance costs......................................
Operating expenses......................................
To ta l................................................
Balance at June 30, 2005...................................
$ 3,769
$ 16,267
$ 1,092
$ 6,536
$147,259 194
$175,117 107 1,196 3
483 2
2 127 1,920 18 6
1 2
27 1,192 (1,196)
(481) 485 10,601 10,601 9,130 1,494 (156)
(11,136) 668 48 48 66 (66) 10,513 1,503 (153) 672 127 (66) 12,596 141,155 141,155 10,468 6,231 16,699 128 128 1,882 1,882 10,468 1,882 147,386 128 159,864
$ 3,814
$16,267 713
$ 6,383 672
$ 27,849 This schedule summarizes the receipts and disbursements in funds required under the Bond Indenture and have been prepared from the trust statements. The balances in the funds consist of cash and investments at original cost. These balances do not include accrued interest receivable, unrealized gain (loss) on investment and $10 held in the revolving fund at June 30, 2005 and 2004.
64
SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY MULTIPLE PROJECT FUND SUPPLEMENTAL SCHEDULE OF RECEIPTS AND DISBURSEMENTS IN FUNDS REQUIRED BY THE BOND INDENTURE FOR THE YEAR ENDED JUNE 30, 2005 (Amounts in thousands)
Debt Proceeds Service Account Account Total Balance at June 30, 2004......................................................................
237,568 1,271 238,839 Additions Investm ent earnings.........................................................................
16,730 46 16,776 Transfer of investment earnings to earnings account................................................
(16,730) 16,730 Transfer to debt service account................................................................
(5,035) 5,023 (12)
Total....................................................................................
(5,035 )
21,799 16,764 Deductions Interest paid...............................................................................
14,130 14,130 Paym ent of principal.........................................................................
7,600 7,600 Total....................................................................................
21,730 21,730 Balance at June 30, 2005......................................................................
232,533 1,340 233,873 This schedule summarizes the receipts and disbursements in funds required under the Bond Indenture and have been prepared from the trust statements. The balances in the funds consist of cash and investments at original cost. These balances do not include accrued interest receivable.
65
SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY SAN JUAN PROJECT SUPPLEMENTAL SCHEDULE OF RECEIPTS AND DISBURSEMENTS IN FUNDS REQUIRED BY THE BOND INDENTURE FOR THE YEAR ENDED JUNE 30, 2005 Debt Service Reserve Account (Amounts in thousand Revenue Fund ds)
Reserve &
General Cost of Operating Contingency Reserve Issuance Fund Fund Fund Fund Acquisition Account Escrow Account Total Balance at June 30, 2004......................
Additions Investm ent earnings........................
Discount on investments.....................
Distribution of investment earnings............
Revenue from power sales...................
Distribution of revenues.....................
Bond proceeds.............................
Transfer to escrow funds required by refunding bond issuance................
O th e r....................................
Total........
Deductions Operating expenses.........................
Construction expenses......................
Premium and interest on investment purchases...
Paym ent of principal........................
Debt issueance costs........................
Interest paid -
non--escrow................
To ta l..................................
Balance at June 30, 2005......................
5,200 $
21,599 $
4,819 $
7,309 $
681 $
39,608 2
1,110 9
3 90 16 1,230 96 13 71 134 314 (98)
(1,110) 1,522 (74)
(224)
(16) 67,627 67,627 18,241 (69,171) 46,133 4,797 100 787 77,197 78,084 (1,257)
(264) 264 1,257 7
674 (681) 17,091 (264) 46,133 5,471 (681) 1,051 78,454 147,255 41,240 41,240 1,394 1,394 12 12 8,805 8,805 924 924 10,190 10,190 18,995 12 41,240 1,394 924 62,565 3,296 $
21,323 $
4,893 $
8,896 $
6,628 808 $ 78,454 124,298 This schedule summarizes the receipts and disbursements in funds required under the Bond Indenture and have been prepared from the trust statements. The balances in the funds consist of cash and investments at original cost. These balances do not include accrued interest receivable, unrealized gain (loss) on investment, and $22 and $20 held in the revolving fund at June 30, 2005 and 2004, respectively.
66
SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY MAGNOLIA POWER PROJECT SUPPLEMENTAL SCHEDULE OF RECEIPTS AND DISBURSEMENTS IN FUNDS REQUIRED BY THE BOND INDENTURE FOR THE YEAR ENDED JUNE 30, 2005 (Amounts in thousands)
Debt Debt Service Service Reserve Account Account Operating Reserve &
Project Reserve Contingency Fund Fund Fund Revenue Fund Total Balance at June 30, 2004...............................
21,462 20,024 79,770 Additions Investment earnings...............................
184 483 802 Discount on investment purchases......................
2 34 Receipt from participants..............................
Transfer to project fund...............................-
(494) 1,417 M PC Transfer.......................................-
9,551 5.135 10.264 136.655 141 137 32 (283)
(640) 1 2
9,617 (9,551) 1,748 70 9,617 O th e r.............................................
T o ta l............................................
D eductions..........................................
Construction expenditures.............................
Interest paid -
non-escrow..........................
T o ta l............................................
"3 rtoo LUJO L UO0 186 (11) 13,842 (142)
(471) 69 13,473 80,432 80,432 15,170 15,170 15,170 80,432 95,602 Balance at June 30, 2005...............................
6,478 20,013 13,180 4.993 9.793 69 54,526 This schedule summarizes the receipts and disbursements in funds required under the Bond Indenture and have been prepared from the trust statements. The balances in the funds consist of cash and investments at original cost. These balances do not include accrued interest receivable and unrealized gain (loss) on investment, and $14 and $16 held in the revolving fund at June 30, 2005 and 2004, respectively.
67
- ACCOUNTING AND H
INVESTMENTS GROUP*
From left to rigbt: Jocelyn Mariano, Lead Utility Accountant, Margarita Felix, Utility Accountant, Alice Tong, Administrative Assistant, Therese Savery, Manager, SCPPA Accounting and Investments, Yolanda Pantig, Assistant Manager, SCPPA Accounting, Joan Ilagan, Investment Manager, and Nina Sanchez, Assistant Investment Manager.
- (Los Angeles Department of Water and Power employees assigned to SCPPA) 68
CITY OF ANAIEIM Customers - Retail..............
I.......
110,835 Power Generated and Purchased (in Megawatt-Hours)
Self-Generated..................... 942,472 Purchased........................ 2,471,928 Total.............................
3,414,400 Total Revenues (000s).................. $297,442*
Operating Costs (000s)................. $274,131 "
°Unauditnd CITY OF BURBANK Customers - Retail.................. 50,633 Power Generated and Purchased (in Megawatt-Hours)
Self-Generated................
124,000 Purchased.................... 1,124,000 Total.........................
1,248,000 Total Revenues (000s).............
$251,835 Operating Costs (O00s)............. $219,868 CITY OF GLENDALE Customers - Retail.................. 83,367 Power Generated and Purchased (in Megawatt-Hours)
Self-Generated................. 217,766 Purchased..................... 1,058,612 Total.........................
1,276,378 Total Revenues (000s)...........
$150,545*
Operating Costs (000s)............. $140,616*
- Unauditnd CITY OF PASADENA Customers Served.................. 61,389 Power Generated and Purchased (in Megawatt-Hours)
Self-Generated.................. 79,273 Purchased.................... 1,342,791 Total.........................
1,422,064 Total Revenues (000s).............. $156,743 Operating Costs (000s)............. $142,516 CITY OF AZUSA Customers Served.............
.. 15,524 Power Generated and Purchased (in Megawatt-Hours)
Self-Generated......
I............
0 Purchased..................... 267,304 Sales Retail......................... 251,266 Total Revenues (000s)............... $34,382*
Operating Costs (000s).............. $32,631
- Unaudited CITY OF(1:
CERRITOS Customers - Retail...................
24 Power Generated and Purchased (in Megawatt-Hours)
Self-Generated.................
10 Purchased.......................... 0 Total..............................
10 Total Revenues (000s)................... $*
Operating Costs (000s).................
- Retailed senvice started July 19. M.
IMPERIAL IRRICATION DISTRICT Customers Served................. 126,000 Power Generated and Purchased (in Megawatt-Hours)
Self-Generated................ 1,105,000 Purchased.................... 2,665,000 Total...............
....... 3,770,000 Total Revenues (000s)........... $499,000 Operating Costs (000s).......... $492,000 CITY OF RIVERSIDE Customers Served................. 103,500 Power Generated and Purchased (in Megawatt-Hours)
Self-Generated................. 318,800 Purchased.................... 2,215,900 Total......................... 2,534,700 Total Revenues (000s).............. $232,809*
Operating Costs (000s)....
$201,728*
- Unaudited CITY OF BANNING Customers - Retail......
11,819 Power Generated and Purchased (in Megawatt-Hours)
Self-Generated....................... 0 Purchased..................... 166,000 Total..........................
166,000 Total Revenues (000s)............... $21,738*
Operating Costs (000s).............. $20,803*
- Unauditod CITY OF COITON Customers - Retail.................. 18,126 Power Generated and Purchased (in Megawatt-Hours)
Self-Generated.................
25;105 Purchased.....
............ 350,729 Total......................... 375,834 Total Revenues (000s)............... $42,142" Operating Costs (000s).............. $42,028*
ilemudited LOS ANGELES DEPARTMENT OF WATER AND POWER Customers Served................ 1,437,300 Power Generated and Purchased (in Megawatn-Hours)
Self-Generated............
15,536,438 Purchased.................. 12,350,271 Total....................... 27,886,709 Total Revenues (000s)............ $2,255,633*
Operating Costs (O0Os)........... $2,076,500*
S*Unauditedt CITY OF VERNON Customers Served................... 2,046 Power Generated and Purchased (in Megawatt-Hours)
Self-Generated...................... 0 Purchased................... 1,368,631 Total........................ 1,368,631 Total Revenues (000s)............. $110,485 Operating Costs (000s).............. $92,911
A WATERSHED YEAR Salt 2005 River Project ANNUAL REPORT MUW'll~
at
Contents Letter to Customers, Bondholders and Shareholders I Letter from the General Manager I 3
4 Energy I 6 Water I 12 Communities I 18 Financial Information I 21 SRP Boards and Councils I 53 SRP 2005 ANNUAL REPORT 11
SRP: Power and Water to the Valley SRP provides electricity to more than 2 million people in a 2,900-square-mile area in the thriving greater Phoenix metropolitan area known as the "Valley."
SRP also is the Valley's largest water supplier, with a water service territory that spans 375 square miles. In addition, SRP manages the 1 3,000-square-mile watershed that supplies a majority of the Valley's surface water. Founded in 1903, SRP is an integrated electric utility, providing generation, transmission and distribution services. It is one of the largest public power utilities in the United States. SRP delivers about 1 million acre-feet of water a year to agricultural, municipal and irrigation water users. Our mission is clear:
To deliver ever-improving contributions to the people we serve through the provision of low-cost, reliable water and power, and community programs, to ensure the vitality of the Salt River Valley."
SRP's positive reputation as a strong customer service N
organization continues. J.D. Power and Associates has ranked SRP No. 1 in the West in customer service for business and/or residential customers seven times in the past seven years. SRP has ranked first among Western states in residential customer service satisfaction for three I
consecutive years, and No. 1 in business customer service satisfaction for the past two years. In 2004, SRP also ranked best in the nation for residential customer service satisfaction.
21SRP 2005 ANNUAL REPORT
Letter to Our Customers, Bondholders and Shareholders Our electric customers, water shareholders and many other stakeholders benefited from a year of exceptionally strong financial results, award-winning customer service and heavy precipitation that curbed a 10-year drought.
The drought engaged SRP, policy makers, urban planners, economists and the public at large. For the first time in recent memory, Valley residents were asked to voluntarily conserve water. And SRP water shareholders were placed on a third year of allocation restrictions for the first time in more than half a century.
It truly was a watershed year As the year progressed, the pendulum swung in the opposite direction.
for SRP.
rained, it snowed, and the winter of 2004-05 became the wettest in more than 10 years. The watersheds of the Salt and Verde rivers, which provide the majority of the surface water for the Valley's needs, responded generously with runoff. The abundant runoff allowed allocation restrictions to be lifted by February and increased SRP's total reservoir storage to 96 percent at the end of the fiscal year.
And the year offered more than just plenty of water. Net revenues were outstanding - $362.5 million on total operating revenues of $2.3 billion. Although retail electric sales were affected by difficulties in the local manufacturing sector, the wholesale energy market was favorable. Fuel prices, primarily for natural gas, continued to be unpredictable.
The power business continued its legacy of adherence to long-standing reclamation principles by providing financial support to the water business, $57 million this fiscal year, to help keep prices low.
This year we added nearly 34,000 electric customers, an increase of 4.1 percent. This growth is fueled by a high quality of life, a unique environment, a strong economy, and an affordable cost of living.
In support of this growth, SRP capped off a five-year historic high in capital investment for generation, transmission and distribution.
We reduced long-term debt by 6 percent, to $2.7 billion, which resulted in a debt ratio of 50.1 percent, the lowest in more than 50 years. Our solid financial performance allowed us to continue to hold bond ratings of AA and Aa2 from Standard & Poor's and Moody's.
We are proud of the year's accomplishments, and we marvel at the continued dedication of our employees to providing stellar service year after year. We have every confidence that SRP will continue its historic commitment to providing superior value and service to our water shareholders, electric customers and communities.
William P. Schrader 4 2 n M. Williams Jr.
President Vice President SRP 2005 ANNUAL REPORT 13
Letter from the General Manager SRP has enjoyed a phenomenal year. Financial results were excellent, our reservoirs are full for the first time in many years, and electric service has continued to be highly reliable, notwithstanding the many challenges of a rapidly expanding customer base.
While we will not know for some time whether the drought on our watershed has ended, SRP's reservoir system performed as designed, allowing us to successfully manage a 1 0-year dry period. Our reliance on surplus Central Arizona Project water has ended for now, but our appreciation for the value of this resource continues.
As we plan for the future, protecting and enhancing our water resources is a high priority for SRP. This year, the Arizona Water Settlements Act (including the Gila River Indian Community Water Rights Settlement) was a major milestone. Also of significant importance is our ongoing effort to resolve conflicting claims to the underflow and aquifers underlying the Verde River and its watershed. In the "Water" section of our report, we discuss these water rights issues, and the status of Blue Ridge Reservoir.
Meanwhile, as a hedge against drought, we are in the initial stages of a program with Valley cities to increase groundwater-pumping capability. This effort will occupy us the remainder of this decade, and will result in an increased ability to overcome limits imposed by future dry periods.
On the electric side, we will continue to examine any changes affecting SRP and our customers resulting from new national energy policy enacted by the U.S. Congress. SRP has worked hard the last several years to anticipate changes impacting our involvement in the wholesale electric market. We have actively participated in the response of our region to initiatives of the Federal Energy Regulatory Commission (FERC) to deregulate the market. The FERC is currently undergoing leadership changes and has signaled an intent to re-examine certain of its policies.
In the meantime, we suspect that retail competition, if and when it resurfaces in Arizona, will take a different course than it did when first initiated. Our early experience suggests that retail marketers will find that back office costs limit their interests to large users and possibly aggregation of small users.
SRP's electric infrastructure presents its own set of challenges. While we are well positioned for the continued growth in customers, generation challenges include the continued operation of the Mohave Generating Station. Installation of emission control equipment must be completed. And, yet to be resolved is the location of an alternative water supply for the slurry pipeline that transports coal from the Black Mesa, 270 miles to the station.
This past year we added Unit 5 at our natural-gas-fired Santan Generating Station; and Unit 6 will be completed within a year. Local generation within our service territory enhances import capability, thereby improving reliability. We also have contracted for a portion of the output of a new coal-fired unit, Springerville 3, in eastern Arizona, which will be available next year. We have secured the option to build another new coal-fired unit, Springerville 4, at the same site. These units constitute attractive additions to SRP's base load resources.
4ISRP 2005 ANNUAL REPORT
We and other regional utilities continue efforts to plan, permit and construct the necessary extra-high-voltage transmission lines necessary to insure reliable service to our growing area. Unlike other regions of the country, we have proceeded with needed transmission infrastructure.
SRP is in a favorable position compared to utilities in slower-growth regions. Arizona's economy consistently outperforms the nation as a whole. The employment rate in the greater Phoenix metropolitan area is expected to continue to grow by nearly 4 percent for the next two years.
Focusing on growth, design requests for new customer installations are at an all-time high.
Population growth in our metropolitan area, however, may not sustain the new construction currently contemplated. As a result, we also plan against scenarios with slower growth, and believe we are prepared to deal with that should it occur.
That said, our service territory in the greater Phoenix metropolitan area currently ranks second in the nation in terms of population growth. Specifically, the southeastern portion of our territory, in northeastern Pinal County, is poised to grow at a significant rate, and we are prepared to meet the needs of these new customers. We are part of a planning group seeking parameters for the development of a significant parcel of state trust land in Pinal County, should it become available for private development.
SRP makes a concentrated effort every year to control operating expenses. Nonetheless some costs, particularly fuel, are resulting in pricing actions that are needed to sustain the continued financial well-being of SRP. We believe our efforts to mitigate the impact of these actions on our customers are appropriate and well received. Like most generators, SRP has seen unprecedented increases in availability and volatility of prices for natural gas, which is the fuel used at our local generating stations. We continue to explore opportunities for natural gas storage in Arizona, and our hedging efforts have been successful in restraining fuel costs to manageable levels.
As a steward of natural resources, SRP maintains a strong commitment to the environment. This year's Electric Retail Customers 858,314 746,368 FY01 FY05 The number of SRP electric customers has jumped by nearly 112,000 or 15 percent, in the past five years.
report highlights many of our efforts, including a new solar energy program, participation in a biomass-fueled generating plant, and growth in our prepaid metering program.
Common throughout our industry is the challenge associated with the aging of America's workforce.
SRP remains proactive in its planning efforts and is considered a benchmark organization within the industry. Through talent assessments and development initiatives, and a robust apprenticeship program, we are effectively managing for future personnel changes vital to our continued success as a progressive utility.
The year's results are due in great part to the efforts of our dedicated, hard working employees.
And, as always, the wisdom and knowledge of our elected officials continue to underscore our successes.
Richard H. Silverman General Manager SRP 2005 ANNUAL REPORT 5
~+.
Navajo Generating Station in northern Arizona is a top-performing plant for SRP and other plant participants. Located four miles east of Page near the Utah border, NGS is owned by a consortium of Western utilities and the U.S.
government, linked by transmission lines. SRP holds 21.7 percent ownership and is station operator, managing three, 750-megawatt (MW) units for a total capacity of 2,250 MW. NGS, which is one of the largest coal-fired generating stations in the West, this year once again performed well above the average for similar plants in the U.S. in terms of reliability and production.
NGS also continues as a top performer in the industry with the least amount of sulfur dioxide emissions (pounds per million) on an annual basis. SRP operates or participates in a number of major generating facilities in Arizona and the Southwest that use thermal and hydroelectric sources.
61SRP 2005 ANNUAL REPORT
Growth, Expansion Highlight Power Year Record-setting customer growth - and capital projects that allow us to stay ahead of that growth - made FY05 a distinctive year for SRP's power business.
SRP's electric service area added nearly 34,000 more customers during the year for a 15 percent increase in customer numbers in five years. For SRP, staying ahead of the curve takes foresight, planning and significant investments in new infrastructure to ensure reliability and stable performance for our customers.
Capital investments over the past five years hit a historic high - $2.48 billion since FY01.
This year, capital expenses averaged nearly
$1 million per day, primarily for service-area generation and distribution system projects.
Enhancing our ability to serve native load is our first priority, and consequently, local generation facility expansions took up the bulk of the capital investment. Local plants provide additional benefits to SRP and our retail customers because they increase load-serving capability and voltage support, making them critical to preserving power system reliability as the system grows.
Of particular importance, commercial operation began this spring for SRP's newest natural gas unit, featuring two combustion The first unit of the Santan Generating Station Expansion Project in Gilbert became commercially operational in April 2005. The new natural gas-fueled unit provides approximately 550 megawatts (MW) to help meet the needs of SRP customers in the Valley. SRP has operated a 300-MW generation station at the site for nearly 30 years; with the expansion, the station now employs about 70 people, including control room operator Judy Johnson.
turbines and one steam turbine at the Santan Generating Station. Another unit is under construction and is scheduled for commercial operation by summer 2006. When the final unit is online, we will have added 825 megawatts (MW) at Santan, one of our Valley generating stations.
Local generation can be critical to system reliability during a catastrophic event such as last summer's fire at a major receiving station on the northwest edge of Phoenix, co-owned by SRP.
With a major import restriction, additional local resources like Santan helped provide the energy needed within the Valley.
Our build-and-buy generation plans of the past few years have produced the results required. Over the past five years, we have added 1,143 MW in owned generation, the bulk of this in plants near or in the Valley, bringing total generation resources at peak hour in FY05 to 7,410 MW (owned and purchased).
Total available resources are sufficient to serve customers in our nearly 3,000-square-mile electric service area for the near term. We anticipate additional generation resources will be built or purchased beginning in FY06 to meet a mix of peaking, intermediate, and base load requirements. New generation options under SRP 2005 ANNUAL REPORT 17
West Valley communities served by SRP electricity are experiencing phenomenal growth as agricultural lands give way to residential and commercial development. For example, over the past decade, Avondale's population grew at a rate of about 120 percent; Peoria's population has more than doubled. These communities offer a wide variety of new residential neighborhoods, ranging from starter homes to luxury, and are expected to continue to develop at record rates. In fact, several Valley cities in SRP's electric service area are among the fastest growing in the nation. Changing land-use patterns and the subsequent growth has resulted in significant load growth for SRP and the need for additional investments in electric infrastructure. Over the past five years, SRP's customer base has grown by nearly 112,000, a 15 percent increase.
8ISRP 2005 ANNUAL REPORT
consideration include renewables, and gas-and coal-fueled resources.
Meanwhile, making efficient use of SRP's existing generation facilities is of paramount importance. Major maintenance, including replacement and repairs, is conducted during scheduled outages. These efforts pay off for SRP and its customers: this past year, power plants such as the nearly 50-year-old Agua Fria Generating Station demonstrated excellent starting-reliability and low forced-outages rates.
The net result? Stable, reliable electric service for SRP customers.
Explosive load growth for SRP is expected to continue, affecting in particular the outer reaches of our service territory. A large number of master-planned communities in Maricopa and Pinal counties are in the concept or construction stages in the Southeast Valley cities of Chandler, Gilbert, Mesa and Queen Creek. New projects are planned in these areas for the next several years. We also are seeing an upsurge of development in the West Valley, with several large planned-communities on tap within the cities of Avondale and Glendale, and in west Phoenix.
Power delivery facilities must keep up with new generation and customer growth. For SRP, sustained load growth in the Valley adds pressure to continually increase import capability through the strategic expansion of the transmission system. Major transmission additions
- both implemented and planned - will ensure that the Valley's import capability, combined with Mesa resident Jim Lacy, an SRP electric customer, was one of the first to join SRP EarthWise Solar Energy. Lacy and others volunteered to install photovoltaic systems at their homes and in return received rebates from SRP in the first year of this program. In addition, SRP customers can receive up to $750 to install solar water heaters in their homes. Customers also may be eligible for a state tax credit of up to 25 percent of the purchase price, or up to
$1,000 on the cost of a solar system.
local generation, stays ahead of forecasted load growth.
SRP now is engaged in a public process to site a new 500-kilovolt (kV) transmission line for the Southeast Valley and central Arizona. The Arizona Power Plant and Transmission Line Siting Committee has recommended approval to the Arizona Corporation Commission (ACC) for the more than 1 00-mile project, which will increase system reliability and bring much-needed energy to customers across central Arizona, especially during peak summer days.
This project and another 500-kV project that was completed in the Southwest Valley the previous year are the direct result of a cooperative regional study conducted by several of the state's electric utilities and the ACC staff.
The study concluded that transmission delivery in central Arizona requires significant expansion to address energy demands by rapid business and residential growth.
As electricity makes its way to customers, our distribution system becomes the focus. SRP invested nearly $183 million this past year in distribution system upgrades and almost
$900 million in the past five years. Distribution capital improvements in FY05 included five new 69-kV substations at key locations around the Valley and expansions at three other substations.
This pace of development has persisted over the past five years.
As well, SRP adds an average of 800 circuit miles of distribution each year: from FY01 to FY05, more than 4,000 underground circuit SRP 2005 ANNUAL REPORT 9
Power System Capital Expenditures FYO 1 -FY05
($thousonds)
Transmission 260,673 Distribution 874,621 Generation 1,346,093 Over the past five years, SRP's capital expenditures reached an all-time high as the power system expanded and improved. For FY05 alone, these expenses totaled $359 million.
One reason? SRP invests prudently in new system upgrades, and in a strategic stair-step fashion so as not to overly impact our valued customers. We are dedicated to keeping our retail pricing as low as possible.
We continue to offer a variety of value-added services and programs for retail customers. This year we launched SRP PowerWise TM a multi-faceted energy information program to help customers get the best value for their energy dollar. Consumers can look for the SRP PowerWiseTM label to easily identify energy-efficient appliances and products at retail locations across the Valley. SRP PowerWise HomesTM promotes energy efficiency in planned communities through partnerships with homebuilders to create new energy-smart homes for buyers.
Meanwhile, SRP's Time-of-Use Plans continue to grow in popularity each year. About 18 percent, or more than 150,000 customers, now participate in these plans, which provide financial incentives for off-peak electricity use.
Another energy-minded program is SRP M-PowerT M
the largest prepay electric program in North America that allows customers to decide how and when they purchase electricity, even on a daily basis. This year, we expanded M-Power with new technology that offers more functionality and maintained 32,500 residential customers as participants.
Our award-winning Web site, www.srpnet.com, offers more than 25 online residential and business services in addition to a wealth of energy-savings information. SRP continues to pursue development of other programs and services that will help our customers save electricity, time and money.
miles were added, bringing our total circuit miles to more than 25,000 miles.
Distribution is the segment of the system where the customer is most impacted by power quality, which can play a critical role in the success of business operations. We continued this year with our commitment to minimize the duration and frequency of distribution outages, and to work on both sides of the meter with highly sensitive customers. Other distribution reliability efforts include underground cable replacement, effective tree trimming practices to prevent outages and hazards, and the systematic replacement or reinforcement of aging wooden poles.
In recent years, electric revenues and new debt have funded SRP's capital projects. Despite the size of these investments, our retail electric prices remain among the lowest in the Southwest.
1OISRP 2005 ANNUAL REPORT
New Sustainable Program "SRP was founded on the principle of resource stewardship. We strive to preserve the balance between serving growing customer, needs and protecting natural resources by incorporating into our core business practices the principles of environmental stewardship, resource conservation, pollution prevention, and regulatory compliance, as well as public outreach, education and partnerships advancing the cause of environmental stewardship in the community."
SRP this year initiated "Sustainable Portfolio Principles," which overlay a forward-looking set of environmentally sound goals and practices into our core power business; A key goal of the Sustainable Portfolio is for SRP to meet 2 percent of its expected retail energy requirements with sustainable resources by 2010.
Toward that goal, SRP this past year contracted for 10 MW of output from a biomass project in Northern Arizona to be operational in 2008. At least 80 percent of this energy will be generated through the burning of Arizona forest thinnings in support of the state's Healthy Forest Initiative.
SRP also is pursuing research-and-development opportunities for residential and commercial fuel cell applications. Testing and evaluation of this environmentally friendly technology is being conducted with Arizona State University and the Electric Power Research Institute.
Our renewable energy resources now include wind, low-impact hydro, solar, geothermal and landfill gas, comprising about 1 percent of our generation resources.
"Sustainable" means not just being environmentally friendly in the way we generate electricity, but'in how we use it as well. SRP offers customers the opportunity to, take an active role in the stewardship mission. This year we launched SRP EarthWise Solar Energy, offering financial incentives to customers who install photovoltaic systems or solar water heaters in their homes or businesses. SRP has committed $1 million per year through 2009 to this program.
SRP's Electric Service Area SRP makes direct sales to customers for all mining loads.
SRP provides electricity to power users in a 2,900-square-mile service area in parts of Maricopa, Gila and Pinal counties.
SRP 2005 ANNUAL REPORT ill
Rimmed by spectacular red-rock formations, the Arizona community of Sedona resides along the banks of Oak Creek on the Verde River watershed, which is a major supply of SRP's surface water to the Phoenix area. Sedona is in a north-central area known as the Verde Valley, where the population has doubled for the past two decades. Water resource management and sustainability are crucial to supporting growth in the Southwest, and SRP supports a myriad of efforts to resolve such issues. This year SRP's Board of Directors approved $500,000 to support a new University of Arizona program that will examine sustainability, hydrologic science and the balance between water supply and demand in'Arizona. SRP also is funding Northern Arizona University's Watershed Research and Education program focused on the Verde River watershed area.
12 ISRP 2005 ANNUAL REPORT
A Watershed Year for SRP and Shareholders From parched conditions to waterlogged watersheds and overflowing reservoirs, it was a remarkable year.
A historic drought dominated the scene when the fiscal year began in May 2004. Below-average precipitation continued to impact SRP watersheds and reservoirs, resulting in continued reliance upon the Valley's groundwater table. The national media focused on Arizona as an example of extreme drought conditions in the West. Virtually every community in the state was affected by the drought.
The drought came close to the "drought of record" in the 1 890s that directly led to the creation of SRP and the construction of Theodore Roosevelt Dam. As the water level dropped, a "bathtub ring" marked the shoreline of Roosevelt Lake, and areas of land were exposed that had not been visible since a mid-1950s drought that emptied the reservoir.
Even as the Salt and Verde reservoir system declined to 40 percent of capacity, SRP's expertise in managing the Valley's water supply was evident throughout the year. SRP published its "Blueprint for Water Management" in summer 2004. Prominent within the Blueprint is an explanation of the many impacts of drought and how sound water-management practices address An important water-management responsibility for SRP is water quality monitoring. SRP monitors the rivers within its watersheds, as well as the canals and groundwater wells within its water service area. SRP has its own state-licensed analytical laboratory where environmental scientists routinely evaluate samples for metals, minerals, volatile organic chemicals and select pesticides. Hilda Marchetti, senior environmental scientist, analyzes samples specifically for metals and inorganic elements.
the challenges of consecutive dry years.
From reduced allocations to supplemental water from the Central Arizona Project (CAP) to water rights protection, SRP continued its historic legacy as the Valley's primary water steward, preserving and conserving water while protecting shareholders' interests. SRP is the Valley's largest raw water supplier, serving the various water needs of Avondale, Chandler, Gilbert, Glendale, Mesa, Peoria, Phoenix, Tempe, Tolleson and Scottsdale.
As the drought continued, water conservation efforts increased. The state, Valley cities, and SRP launched public education appeals to encourage voluntary conservation. SRP provided several water conservation and efficiency programs, including the DesertWise Landscape research project, which provides communities with information on water use for various plant and turf landscapes. Outdoor applications account for the majority of residential water use, thus providing significant potential for water savings.
As a hedge against drought conditions, SRP has been "banking" supplies effectively through underground water storage. Water that otherwise would be unused is delivered to large basins and allowed to percolate underground, providing a low-cost answer to water storage. The SRP-SRP 2005 ANNUAL REPORT 113
This year saw the resolution of a number of major issues that clarify water resource planning in Arizona. For example, the scenic Blue Ridge Reservoir, atop the Mogollon Rim on the Coconino National Forest 135 miles north of the Valley, has joined the SRP surface water supply. Blue Ridge has a storage capacity of 15,000 acre-feet of water and is located on the Little Colorado River watershed. Acquisition of the lake and its water production facilities will assist in satisfying SRP's obligations to the Gila River Indian Community, help to improve the water supply situation in northern Gila County, and enhance resources for water shareholders. The agreement regarding Blue Ridge is one of several historic water agreements between SRP and Phelps Dodge Corp.
Protecting water rights for our shareholders is as important to us as managing SRP's system of canals and reservoirs.
14 ISRP 2005 ANNUAL REPORT
operated Granite Reef Underground Storage Project (GRUSP) in the East Valley, one of the largest such projects in the nation, has been storing excess CAP water now for 10 years.
GRUSP has banked in excess of 750,000 acre-feet of water - enough to fill Saguaro Lake more than 10 times.
In July 2004, SRP completed the land purchase for a second project, this time in the West Valley. When the second project is complete, SRP and participating cities will have the permitted capacity to store up to 275,000 acre-feet of water every year. (One acre-foot is enough water to meet the annual needs of a typical household for one year.) Both projects are a cooperative effort between SRP and Valley cities.
Surface water supplies continued to diminish during the summer, and a light monsoon season brought little relief. After just 38 days, about five weeks short of normal, the summer monsoon season was over. Capacity at SRP's reservoirs continued to drop and in September, the SRP Board of Governors continued reduced water allocations for shareholders to preserve precious surface water supplies.
In fall 2004, Governor Janet Napolitano unveiled the state's first comprehensive drought preparedness plan. The plan's focal points are a drought monitoring system to provide early warning of future drought conditions, and proactive mitigation strategies to help reduce drought impacts. A task force is developing a SRP brings water from Arizona's high country to the desert through a complex system of dams, lakes, canals and laterals. After assessing all water orders, SRP releases the requested amount of water from storage dams into the seven main canals crossing the Valley.
SRP water services employee Gabriel Lopez opens a gate to release water from a canal into a system of laterals.
Urban Land Growth U
Urban L
Agriculture 25 12%/
1995 2005 In SRP's water service area, land use continues to shift to urban.
statewide water conservation strategy focused on hard-hit rural areas.
In the late fall, rain and snow on the watersheds of the Salt and Verde rivers began to accumulate, leading to marginal improvement in total system storage. December's above-normal precipitation provided a turning point: runoff on the watersheds increased the overall capacity of SRP's reservoir system to 46 percent.
In the final hours of 2004, SRP released water from Bartlett Dam on the Verde River to make room for more anticipated runoff. For the first time since 1998, Valley residents saw water flowing through the normally dry Salt River.
Inflatable dams that create Tempe Town Lake on the Salt River were deflated to allow the released water to flow downstream.
SRP 2005 ANNUAL REPORT 115
SRP Water Deliveries CAP/other SRP sr surface water 35%
37%
urface water SRP groundwater 28%
Precipitation was twice normal in January and, by early February, SRP's reservoirs had made an extraordinary rebound, necessitating additional water releases from dams that for years had held dwindling supplies. The Board of Governors, in response to the improved circumstances, rescinded allocation reductions in place since 2003.
Precipitation from October through February was 77 percent greater than normal, creating the most significant runoff season since the beginning of the drought.
Winter storms increased total reservoir storage dramatically, more than double the previous year. In less than two months, Roosevelt Lake reached its highest-ever water level. For the first time since the dam height was raised a decade ago, new water-conservation storage space behind Roosevelt Dam was filling up.
All told for the fiscal year, water deliveries were about 1 million acre-feet, gauged runoff was 80 percent above normal and water in storage was 96 percent of capacity.
Once again, the year demonstrated the value of SRP's extensive water management system in ensuring the Valley's water supply and continued economic prosperity that its citizens have enjoyed for so many years. At fiscal year-end, most of Arizona was still classified as being in "moderate to extreme" drought; some areas were recovering from drought but were not yet back to normal.
Water conservation will continue to play an important role in SRP's water management practices. Among its other conservation efforts, SRP now offers the DesertWise HomeTM program, which incorporates water-saving features into the exterior and interior design of new homes. SRP teamed with the City of Phoenix and Pulte Homes to offer the first DesertWise Home models at two subdivisions in southwest Phoenix. The program is open to all Valley cities and homebuilders.
SRP hydrologists Dallas Reigle, left, and Tim Skarupa routinely visit the Arizona high country during the winter months to measure snow pack. An estimate on water content is derived from the measurements, which is then used to develop spring runoff forecasts. These forecasts help SRP better manage its water storage system by providing an advance picture of expected surface water supplies.
16 iSRP 2005 ANNUAL REPORT
Big Year for Water Rights It has been called the largest water rights settlement in the history of the United States.
Congress approved and the president signed into law the Arizona Water Settlements Act, which resolves a complex web of claims by..
dozens of parties. In particular, it settles water rights disputes affecting more than 3 million residents of Maricopa, Pima, Pinal and Yavapai counties and millions of acre-feet of water.
SRP supported passage of the measure because our shareholders have some of the most extensive senior water rights on the Salt and Verde rivers. Protecting those rights is an important element of our water stewardship responsibilities.
The resolution of the Gila River Indian Community's (GRIC) water rights claims provides further certainty of SRP shareholders' water supply. This allows SRP to better plan for and manage the water supply and delivery system.,
The GRIC's claims were the largest and most contentious made to the water supply used by SRP shareholders. The settlement establishes a business agreement with GRIC similar to others SRP has with third parties. SRP will provide an average of 20,000 acre-feet of water to the GRIC from the Salt and Verde rivers. SRP also will utilize this system to store, exchange and deliver water from the Central Arizona Project to the GRIC.
SRP's Water Service Area Peoria Glendale' Avondale SRP administers water rights in a 248,239-acre area in central Arizona, indicated in green.
SRP 2005 ANNUAL REPORT 17
Through programs like Learning Grants by SRP, schoolchildren across Arizona are drawn into more-innovative educational efforts that support teachers and promote academic achievement in math, science and technology. This year, Lindberg Elementary School students in Mesa were provided with a grant to develop "math packs" to use at home to help them learn basic math skills.
Lindbergh students are, clockwise from top left: Kristopher Yanez, Alyssia Clark, Logan Millet, Oscar Blanco, Daisy Portillo and Justin Rodriquez. This year SRP awarded 13 grants totaling nearly $50,000 to schools in Maricopa, Pinal and Yavapai counties to enable teachers to create programs like "math packs," a Mathematical Exploration Center, an Afterschool Achievers Club and a Family Math Night Carnival. Public, charter and private schools can apply for up to $5,000 to support such programs.
18 ISRP 2005 ANNUAL REPORT
Touching More Lives Through Outreach Community stewardship is the hallmark of SRP's corporate culture. Beyond providing water and power services, we are committed to sustaining and improving life in the Valley through programs that help inspire children to learn, build a qualified workforce, create community-based services, expand cultural offerings and promote safety.
This year we were able to touch more lives than ever through new outreach efforts and expanded partnerships with organizations that share our community commitment.
Our education efforts reached more than 200,000 students through programs supported by $750,000 in corporate contributions. For example, Learning Grants by SRP foster student projects that promote academic achievement in state-mandated competencies in math, science and technology. These programs reach schoolchildren with learning opportunities that otherwise would not be funded, and contribute to ensuring the goal of a well-educated and qualified workforce for the future.
Helping students and teachers understand the delicate balance between the environment and human needs is the focus of our partnership with the Arizona Foundation for Resource Education.
George Martin, science teacher at South Pointe High School in Phoenix, led a team of students in SRP's annual Solar Spectacular boating regatta on Tempe Town Lake.
With the help of SRP funding grants, dozens of high school students research renewable energy, purchase and install photovoltaic equipment on one-person boats, and compete in the two-day regatta. Solar Spectacular inspires innovation and environmental awareness among students who may someday become engineers and scientists.
AFRE is a non-profit, collaborative network of Arizona's natural-resource businesses and industries that provides training and professional development opportunities for K-1 2 teachers statewide. This year we offered financial assistance to AFRE, and provided water and energy workshops to more than 1,100 teachers who, in turn, will influence 85,000 students to become the environmental stewards of tomorrow.
Similarly, SRP introduced Arizona teachers to a model curriculum on renewable-energy.
"Powering Our Future" is a unique, computer-based state-of-the-art primer on renewable energy and energy conservation for grades 4-12.
SRP also is addressing the unique education needs of the Hispanic community, a significant and growing segment of our customer base. As part of this effort, we joined with the Rodel Charitable Foundation of Arizona last year to recognize and reward exemplary teachers in schools with high-need student populations. Top-performing teachers at these schools are offered financial incentives to stay in their teaching roles and formally mentor upcoming teachers-in-training. The goal is to improve the overall quality of classroom instruction and encourage young teachers to remain in the profession.
SRP 2005 ANNUAL REPORT 119
SRP sponsored awards for two Hispanic teachers and 12 student teachers who work in schools within the SRP service territory with predominantly Hispanic populations.
In addition to K-12 educational support, SRP offers substantial assistance to university initiatives that align with SRP business interests and objectives. This past year, as Arizona endured a historic drought, SRP committed another five years of funding to Northern Arizona University for a comprehensive study of the Verde River watershed and the water supply and demand issues that will affect growth and economic development in Arizona.
At SRP, we remain committed to extending our programs to all the communities we serve. In northern Pinal County, a fast-growing area in our service territory, we provided labor and funding to build a new, fully equipped playground for children who are assisted by the nonprofit Against Abuse program. This human services project is representative of our commitment to a broad cross-section of community needs.
Safety is priority one -
for our employees, for our electric customers, water shareholders and communities. SRP Safety ConnectionTM distributes electric and water safety information to teach children and adults to stay safe around electric infrastructure and all bodies of water including canals and swimming pools. Last year, we distributed over 150,000 free water and electric safety materials to schoolchildren in kindergarten though third grade. Our efforts were acknowledged by the Phoenix Fire Department with a "Salute to Excellence" award, and with a "Compassionate Action Water Safety Award" from the American Red Cross.
SRP VOLUNTEERS continues to be a unique model for community service. Employee volunteers last year participated in a special tutoring project that boosted standardized test results for students at Tempe's Arredondo Elementary School. More than 95 percent of the second-through fifth-graders receiving tutoring showed improvement in test scores as part of this first-year program.
Our volunteers also completed their 10 th Habitat for Humanity Home in metropolitan Phoenix. All told, SRP VOLUNTEERS contributed nearly 700,000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> of community service last year, earning SRP a "Championship Award" from The Volunteer Center of Maricopa County.
Cultural life in the communities we serve is important to SRP. We provide funding to major institutions like the Heard Museum, the Phoenix Symphony, Ballet Arizona, the Arizona Theatre Company and the Arizona Opera. We underwrite smaller organizations like the Black Theatre Troupe, the Pueblo Grande Museum and the Southwest Shakespeare Theatre. SRP grants also help build new cultural facilities like the Mesa Arts Center, a visual and performing arts campus opening this year to serve East Valley communities.
,We believe this kind of support, along with our underwriting of other community-based, social service agencies and local development groups, helps fulfill SRP's commitment to the communities we serve. All told, SRP employees, through the Employee Boosters Fund, gave more than $1 million to nonprofit organizations in the state last year. SRP corporate contributions endowed nearly $2.4 million to more than 300 nonprofits, with whom we share a vision for the continued vitality and high quality of life for all of Arizona.
201SRP 2005 ANNUAL REPORT
Debt Ratio (percent) 57.3 56.6 56.0 55.2 50.1 FYO 1 FY02 FY03 FY04 FY05 SRP's debt ratio in FY05 was the lowest in more than 50 years.
SRP Financial Information Management's Financial and Operational Summary Combined Financial Statements 22 Debt Service Coverage Ratio 4.72 3.09 2.23 2.39 FY01 FY02 FY03 FY04 FY05 SRP's debt service coverage ratio picked up ground in FY05 as the increase in net operating revenues resulted in an increase in funds available for debt service on revenue bonds and subordinated debt.
26
'Notes to Combined Statements Report of Independent 1 30 Auditors 1
52 Net Financing Costs
($thousands) 170,540 1,599 138,135 105,637 FY01 FY02 FY03 FY04 FY05 SRP's net financing costs continued to decrease in FY05 primarily due to reduced interest expenses on bonds andother obligations.
SRP 2005 ANNUAL REPORT 121
Management's Financial This section explains the general financial condition and results of operations for SRP. SRP includes the Salt River Project Agricultural Improvement and Power District (the "District"),
its subsidiaries, and the Salt River Valley Water Users' Association. The results of these entities are combined for financial reporting purposes.
Overview of Business The District owns and operates an electric system which generates, purchases, transmits and distributes electric power and energy, and provides electric service to residential, commercial, industrial and agricultural power users in a 2,900-square-mile service territory spanning portions of Maricopa, Gila and Pinal counties, plus mining loads in an adjacent 2,400-square-mile area in Gila and Pinal counties.
The District remains a vertically integrated organization. It is developing additional generation, transmission and distribution resources to keep pace with load growth. The District pursues both short-term and long-term purchases, refinements to its conservation programs, building its own generation, and acquiring existing generation resources.
For example, during the past fiscal year the District completed negotiations for a long-term purchase of 100 megawatts (MW) of output frorr the Unit 3 expansion of the Springerville Generating Station, located in Springerville, Ariz. Additionally, the District obtained the rights to build a 400 MW coal-fired unit (see page 25) in the future on the same site. This development i.
subject to numerous conditions and no assurance can be given that such conditions will be satisfied. The District also has completed construction of a new gas-fired unit, adding
& Operational Summar'y 550 MW, at the Santan Generating Station in Gilbert, Ariz., for commercial operation beginning spring 2005.
SRP manages a system of dams and reservoirs, and has responsibility for the construction, maintenance and operation of a supply system to deliver raw water for irrigation and municipal treatment purposes. It provides the water supply for an area of 248,239 acres located within the major portions of the cities of Phoenix, Avondale, Glendale, Mesa, Tempe, Chandler, Gilbert, Peoria, Scottsdale and Tolleson.
The District's subsidiaries include New West Energy Corporation, which supports the District's energy services activities in Arizona; Papago Park Center, Inc., which manages a mixed-use commercial development known as Papago Park Center, located on land owned by the District adjacent to its administrative offices; and SRP Captive Risk Solutions, Limited, which is a domestic captive insurer incorporated in January 2004 to access property/boiler and machinery insurance coverage under the Federal Terrorism Risk Insurance Act of 2002 for certified acts of terrorism.
Results of Operations SRP's net revenues for the fiscal year ended I
April 30, 2005, were $362.5 million compared to $112.2 million for the previous year. Total operating revenues were $2.3 billion for FY05, compared to $2.1 billion for FY04. The increased revenue this past year was primarily s
the result of continued growth in the greater Phoenix metropolitan area, the wholesale sales market, and the fuel and purchased power component of rates.
22 ISRP 2005 ANNUAL REPORT
Some specifics are:
- Total customers increased 4.1 percent from the previous year, with 92 percent of the increase attributed to the residential class of customers.
- Excess resources combined with high wholesale energy market prices, which are driven by high natural gas prices, resulted in a 33.3 percent increase in wholesale revenues compared to the prior year.
- SRP recovered $59.3 million from previously under-collected fuel and purchased power expenses during the year.
- Operating expenses were $1.8 billion, compared with $1.9 billion the previous year.
The high market price of natural gas increased both fuel and purchased power expenses by about 5 percent and 16 percent, respectively.
The increases in fuel and purchased power expenses were offset by a nearly 28 percent decrease in depreciation expense. The termination of the Desert Basin Generating Station capital lease, as well as the completed amortization of the Competitive Transition Charge regulatory asset in May 2004, contributed to the decrease over the prior year.
o In water operations, delivery revenues were $12.8 million compared to $11.8 million in FY04. Additional revenues were realized near the end of FY05 as a result of providing excess Central Arizona Project water to the newly activated generating unit at Santan. Total water operating expenses were the same year to year.
Accounting Issues The Company adopted FSP 106-2, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003" in August 2004. The Medicare Prescription Drug, Improvement and Modernization Act of 2003 O&M Dollars FY05 Admin/
Water operations other 8%
Generation 4%
14%
Transmission &
distribution 8%/
Depreciation
- 17%
Purchased power 20%
Taxes & tax equivalents 6%
Fuel 23%
About 65 percent of SRP's expenses in FY05 directly supported the power system to provide low-cost, reliable electricity. The remaining 35 percent covered water operations, administration, taxes and asset depreciation.
(Medicare Act) was signed into law in December 2003 and establishes a prescription drug benefit, as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare's prescription drug coverage. FSP 106-2 provides guidance on the accounting for the effects of the Medicare Act for employers that sponsor postretirement health care plans that provide prescription drug benefits, and requires those employers to provide certain disclosures regarding the effect of the federal subsidy provided by the Medicare Act.
For a detailed explanation of the effects of FSP 106-2 on the District's financial results and other recently issued accounting standards, see Note 2 in the accompanying notes to the Combined Financial Statements.
The District adopted Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" (SFAS No. 143),
on May 1, 2003. SFAS No. 143 requires the recognition and measurement of liabilities for SRP 2005 ANNUAL REPORT 123
legal obligations associated with the retirement of tangible long-lived assets. Under the standard, these liabilities are recognized at fair value as incurred and capitalized as part of the cost of the related tangible long-lived assets. Accretion of the liabilities, due to the passage of time, is an operating expense and the capitalized cost is depreciated over the useful life of the long-lived asset. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which a legal obligation exists under enacted laws, statutes, and written or oral contracts, including obligations arising under the doctrine of promissory estoppel. For a detailed explanation of the effects of SFAS No. 143 on the District's financial results and other recently issued accounting standards, see Note 2 in the accompanying notes to the Combined Financial Statements.
Energy Risk Management Program The District's mission to serve its retail customers is the cornerstone of its risk management approach. The District builds or acquires resources to serve retail customers, not the wholesale market. However, as a summer-peaking utility, there are times during the year when the District's resources and/or reserves are in excess of its retail load, thus giving rise to wholesale activity. The District has an Energy Risk Management Program to limit exposure to risks inherent in retail and wholesale energy business operations by identifying, measuring, reporting and minimizing exposure to market, credit and operational risks. To meet the goals of the Energy Risk Management Program, the District uses various physical and financial instruments, including forward contracts, futures, swaps and options. Certain of these transactions are accounted for under SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS No. 133). For a detailed explanation of the effects of SFAS No. 133 on the District's financial results, see Note 3 in the accompanying notes to the Combined Financial Statements.
The Energy Risk Management Program is managed according to a policy approved by the District's Board of Directors (Board), and overseen by a Risk Oversight Committee. The policy covers wholesale market, credit and operational risks and includes portfolio strategies, authorizations, value-at-risk limits, stop loss limits, and duration limits. The Risk Oversight Committee is composed of senior executives. The District maintains an Energy Risk Management Department, separate from the energy marketing area, that regularly reports to the Risk Oversight Committee. In addition, the District has established a credit reserve for its activity in wholesale markets. The District believes that its existing risk management structure is appropriate and that any exposures are adequately covered by existing reserves.
Electric Pricing The District has a diversified customer base, with no single retail customer providing more than 1.4 percent of its operating revenues. The District has implemented projects and programs geared toward enhancing customer loyalty by offering customers a range of pricing and service options. Moreover, the District is one of the low-price leaders in the Southwest.
The District is a summer-peaking utility and for many years has made an effort to balance the summer-winter load relationships through seasonal price differentials. In addition, the District prices on a time-of-day basis for large commercial and industrial customers, residential customers, and certain small commercial users.
On Nov. 1, 2004, a 1.5 percent general price increase in retail prices became effective.
This increase, approved by the District's Board in April 2004 and affirmed by the Board in 24 !SRP 2005 ANNUAL REPORT
Electric Retail Revenues
($millions) 1,709 FY01 FY05 Retail revenues were up nearly 18 percent in FY05 from FY01.
September 2004, was the first general price increase in more than 10 years.
In October 2004, the District Board approved a change to the Fuel and Purchased Power Adjustment Mechanism effective in November for the remainder of the fiscal year.
The adjustment charge was a direct pass-through of expenses and resulted in an average annual increase in retail customer bills of 3.7 percent.
In April 2005, the District's Board approved the operating budget for fiscal year 2006 and, based on that budget, approved fuel-related prices under the Fuel and Purchased Power Adjustment Mechanism for FY06. The fuel and purchased power prices established will be higher in the summer and lower for the upcoming winter season, resulting in an average annual increase in retail customer bills of 1.3 percent.
The District's Board also authorized the funding of the Rate Stabilization Fund.
Rate Stabilization Fund In April 2005, the District's Board elected to designate $55 million of proceeds from FY05 to offset fuel-related expenses and to help stabilize the impact of fuel and purchased power prices to retail customers over the next two fiscal years. The Board authorized the transfer of the funds into the Rate Stabilization Fund, to be used in concert with the Fuel and Purchased Power Adjustment Mechanism to cover fuel related expenses and/or to stabilize future prices related to fuel during fiscal years 2006 and 2007.
Approximately $46.2 million of this fund will be used in FY06 against fuel expenses incurred for FY07. The Rate Stabilization Fund will assist the District in smoothing out the impact of fluctuating fuel prices.
Capital Improvement Program The Capital Improvement Program is driven by the need to expand the generation, transmission and distribution systems of the District to meet growing customer electricity needs and to maintain a satisfactory level of service reliability. Of the total Capital Improvement Program, 35 percent of the funds are directed to generation projects. These include the potential construction of Unit 4 at the Springerville Generating Station, improvements required for continued operation at Mohave Generating Station in southern Nevada, the completion of another unit at Santan Generating Station, and the installation of steam generators at the Palo Verde Nuclear Generating Station.
Another 28 percent of the funds are planned for expansion of the electrical distribution system to meet new growth and to replace aging underground cable. The addition of new 69 kilovolt transmission facilities and the construction of a new high-voltage transmission line account for an additional 6 percent of the funds.
The program also allocates funding for undetermined future projects at various generating stations.
The District pays a portion of the cost of its Capital Improvement Program from internally generated funds and a portion from the proceeds of Revenue Bonds.
SRP 2005 ANNUAL REPORT 125
COMBINED BALANCE SHEETS As of April 30, 2005 and 2004 (Thousands)
Assets 2005 2004 UTILITY PLANT Plant in service -
Electric 7,899,197
$ 7,262,819 Irrigation 267,928 252,595 Common 418,716 417,006 Total plant in service 8,585,841 7,932,420 Less - Accumulated depreciation on plant in service (3,925,661)
(3,720,539)
,4,660,180 4,211,881 Plant held for future use 3,076 14,341 Construction work in progress 414,626 739,295 Nuclear fuel, net 39,834 40,503 5,117,716 5,006,020 OTHER PROPERTY AND INVESTMENTS Non-utility property and other investments 112,326 131,507 Segregated funds, net of current portion 490,518 437,919 602,844 569,426 CURRENT ASSETS Cash and cash equivalents Rate Stabilization Fund Temporary investments Current portion of segregated funds Receivables, net of allowance for doubtful accounts Fuel stocks Materials and supplies Other current assets 288,429 55,000 135,081 131,000 220,820 34,583 80,278 78,659 1,023,850 280,962 60,750 96,756.
177,664 33,257 72,875 62,166 784,430 DEFERRED CHARGES AND OTHER ASSETS 322,273 303,977
$ 7,066,683
$ 6,663,853 The accompanying notes are an integral part of these combined financial statements.
26 !SRP 2005 ANNUAL REPORT
COMBINED BALANCE SHEETS As of April 30, 2005 and 2004 Capitalization and Liabilities (Thousands) 2004 2005 LONG-TERM DEBT
$ 2,727,348 2,912,849 ACCUMULATED NET REVENUES AND OTHER COMPREHENSIVE INCOME 2,714,561 2,381,390 TOTAL CAPITALIZATION 5,441,909 5,294,239 CURRENT LIABILITIES Current portion of long-term debt 274,778 170,029 Accounts payable 172,001 126,651 Accrued taxes and tax equivalents 68,974 67,177 Accrued interest 44,000 45,796 Customers' deposits 53,547 49,659 Other current liabilities 171,400 151,999 784,700 611,311 DEFERRED CREDITS AND OTHER NON-CURRENT LIABILITIES 840,074 758,303 COMMITMENTS AND CONTINGENCIES (Notes 5,7,8,9,10,11 and 12)
$ 7,066,683 6,663,853 The accompanying notes are an integral part of these combined financial statements.
SRP 2005 ANNUAL REPORT 127
COMBINED STATEMENTS OF NET REVENUES AND COMPREHENSIVE INCOME (LOSS)
For the years ended April 30, 2005 and 2004 2005 (Thousands) 2004 OPERATING REVENUES Retail electric 1,709,213 1,622,305 Water 12,786 11,818 Other 529,724 443,191 Total operating revenues 2,251,723 2,077,314 OPERATING EXPENSES Power purchased Fuel used in electric generation Other operating expenses Maintenance Depreciation and amortization Taxes and tax equivalents Total operating expenses 358,697 425,880 429,799 193,489 302,198 105,475 1,815,538 436,185 310,019 406,034 436,541 196,58.8 417,522 100,693 1,867,397 209,917 Net operating revenues OTHER INCOME (EXPENSES)
Interest income Other income (expenses), net Total other income (expenses), net Net revenues before financing costs 25,241 6,661 31,902 468,087 23,573 5,042 28,615 238,532 FINANCING COSTS Interest on bonds Capitalized interest Amortization of bond discount/premium and issuance expenses Interest on other obligations Net financing costs 118,229 (24,189)
(9,642) 21,239 105,637 131,264 (23,327)
(9,386) 17,054 115,605 NET REVENUES BEFORE CUMULATIVE EFFECT OF 362,450 122,927 CHANGE IN ACCOUNTING PRINCIPLE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING (10,707)
PRINCIPLE NET REVENUES 362,450, 112,220 OTHER COMPREHENSIVE INCOME (LOSS)
(29,279) 65,242 COMPREHENSIVE INCOME 333,171 177,462 The accompanying notes are an integral part of these combined financial statements.
28 ISRP 2005 ANNUAL REPORT
COMBINED STATEMENTS OF CASH FLOWS For the years ended April 30, 2005 and 2004 (Thousands) 2005 2004 CASH FLOWS FROM OPERATING ACTIVITIES Net revenues Adjustments to reconcile net revenues to net cash provided by operating activities:
Depreciation, amortization and accretion Postretirement benefits expense Amortization of provision for loss on long-term contracts Amortization of net bond discount/premium and issuance expenses Amortization of spent nuclear fuel storage Gain on sale of capital assets Cumulative effect of change in accounting principle Decrease (increase) in -
Fuel stocks and materials & supplies Receivables, including unbilled revenues, net Other assets Increase (decrease) in -
Accounts payable Accrued taxes and tax equivalents Accrued interest Current liabilities Deferred credits and other non-current liabilities 362,450 112,220 313,727 43,409 (13,280)
(9,642) 1,826 (7,610)
(8,729)
(43,156)
(50,497) 45,350 1,797 (1,796) 23,289 41,657 428,283 43,800 (13,281)
(9,386) 1,641 (8,211) 10,707 (5,764)
(8,694)
(6,883)
(15,970) 3,003 (8,602) 13,760 65,916 Net cash provided by operating activities 698,795 602,539 CASH FLOWS FROM INVESTING ACTIVITIES Additions to utility plant, net (414,530)
(607,174)
Proceeds from disposition of assets 23,923 8,487 Purchases of investments (336,822)
(213,586)
Sales and maturities of securities 202,636 174,851 Investment in Rate Stabilization Fund (55,000)
Decrease (increase) in segregated funds (80,807) 138,610 Net cash used for investing activities (660,600)
(498,812)
CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from issuance of revenue bonds 122,110 Proceeds from Desert Basin finance lease 282,680 Proceeds from issuance of commercial paper 100,000 Repayment of long-term debt, including refundings (171,334)
(377,484)
Payment of capital lease obligations (251,365)
Other proceeds from financing activities 40,606 3,653 Net cash used for financing activities (30,728)
(220,406)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 7,467 (116,679)
BALANCE AT BEGINNING OF YEAR IN CASH AND CASH EQUIVALENTS 280,962 397,641 BALANCE AT END OF YEAR IN CASH AND CASH EQUIVALENTS 288,429 280,962 SUPPLEMENTAL INFORMATION Cash paid for interest (net of capitalized interest) 1117,075 133,593 Non-cash financing activities -
Loss on defeasance (3,990)
The accompanying notes are an integral part of these combined financial statements.
SRP 2005 ANNUAL REPORT 29
NOTES TO COMBINED FINANCIAL STATEMENTS April 30, 2005 and 2004 (1) Basis of Presentation:
The Company - The Salt River Project Agricultural Improvement and Power District (the District) is an agricultural improvement district organized in 1937 under the laws of the State of Arizona. It operates the Salt River Project (the Project), a federal reclamation project, under contracts with the Salt River Valley Water Users' Association (the Association), by which it has assumed the obligations of the Association to the United States of America for the care, operation and maintenance of the Project. The District owns and operates an electric system that generates, purchases, transmits and distributes electric power and energy, and provides electric service to residential, commercial, industrial and agricultural power users in a 2,900 square mile service territory in parts of Maricopa, Gila and Pinal Counties, plus mine loads in an adjacent 2,400 square mile area in Gila and Pinal Counties. The Association, incorporated under the laws of the Territory of Arizona in 1903, operates an irrigation system as the agent of the District.
In 1997, the District established a wholly-owned, taxable subsidiary, New West Energy Corporation (New West Energy), to market, at retail, energy available to the District that was surplus to the needs of its retail customers, and energy that might have been rendered surplus in Arizona by retail competition in the supply of generation. However, as a result of the turmoil in the Western energy markets, New West Energy discontinued marketing excess energy in 2001, although it may resume this activity in the future. New West Energy now primarily supports the District's energy services activities in Arizona.
Possession and Use of Utilily Plant - The United States of America retains a paramount right or claim in the Project that arises from the original construction and operation of certain of the Project's electric and water facilities as a federal reclamation project. Rights to the possession and use of, and to all revenues produced by, these facilities are evidenced by contractual arrangements with the United States of America.
Principles of Combination - The accompanying combined financial statements reflect the combined accounts of the Association and the District (together referred to as SRP). The District's financial statements are consolidated with its four wholly-owned taxable subsidiaries; New West Energy, SRP Captive Risk Solutions, Limited (CRS), Papago Park Center, Inc. (PPC) and Springerville Four, LLC (Springerville Four). PPC is a real estate management company. CRS is a domestic captive insurer incorporated in January 2004 to access property/boiler and machinery insurance coverage under the Federal Terrorism Risk Insurance Act of 2002 for certified acts of terrorism. Springerville Four is a limited liability company that holds the rights to construct a fourth unit at Springerville Generating Station. All material inter-company transactions and balances have been eliminated.
Regulation and Pricing Policies - Under Arizona law, the District's publicly elected Board of Directors (the Board) has the authority to establish electric prices. The District is required to follow certain public notice and special Board meeting procedures before implementing any changes in the standard electric price plans.
(2) Significant Accounting Policies:
Basis of Accounting - The accompanying combined financial statements are presented in conformity with accounting principles generally accepted in the United States of America (GAAP) and reflect the pricing policies of the Board. The District's "regulated" operations apply Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71), while "non-regulated" operations follow GAAP for enterprises in general. Classification of regulated and non-regulated operations is determined in accordance with applicable GAAP accounting guidelines.
By virtue of SRP operating a federal reclamation project under contract, with the federal government's pre-emptive rights, asset ownership and certain approval rights, SRP is considered for financial reporting purposes to follow accounting standards as set forth by the Federal Accounting Standards Advisory Board (FASAB). Entities reporting in accordance with the standards issued by the Financial Accounting Standards Board (FASB) prior to October 19, 1999 (the date the American Institute of Certified Public Accountants (AICPA) designated the FASAB as the accounting standard setting body for entities under the federal government) are permitted to continue to report in accordance with those standards. Consequently, SRP's financial statements are reported in accordance with FASB standards.
30 iSRP 2005 ANNUAL REPORT
NOTES TO COMBINED FINANCIAL STATEMENTS April 30, 2005 and 2004 The preparation of financial statements in compliance with GAAP requires management to make estimates and assumptions that affect the reported amounts in the financial statements and disclosures of contingencies. Actual results could differ from the estimates.
Utility Plant - Utility plant is stated at the historical cost of construction, less any impairment losses. Capitalized construction costs include labor, materials, services purchased under contract, and allocations of indirect charges for engineering, supervision, transportation and administrative expenses and capitalized interest or an allowance for funds used during construction (AFUDC).
AFUDC is the estimated cost of funds used to finance plant additions and is recovered in prices through depreciation expense over the useful life of the related asset. The cost of property that is replaced, removed or abandoned, together with removal costs, less salvage, is charged to accumulated depreciation.
Composite rates of 4.42% and 4.56% were used in fiscal years 2005 and 2004 to calculate interest on funds used to finance construction work in progress, resulting in $24.2 million and $23.3 million of interest capitalized, respectively.
Depreciation expense is computed on the straight-line basis over the estimated useful lives of the various classes of plant assets.
The following table reflects the District's average depreciation rates on the average cost of depreciable assets, for the fiscal years ended April 30:
2005 2004 Average electric depreciation rate 3.49%
3.57%
Average irrigation depreciation rate 2.44%
2.61%
Average common depreciation rate 5.52%
4.38%
Bond Expense - Bond discount/premium and issuance expenses are amortized using the effective interest method over the terms of the related bond issues.
Allowance for Doubtful Accounts - The District has provided for an allowance for doubtful accounts of $16.7 million and $17.9 million as of April 30, 2005 and 2004, respectively.
Nuclear Fuel - The District amortizes the cost of nuclear fuel using the units of production method. The nuclear fuel amortization and the disposal expense are components of fuel expense. Accumulated amortization of nuclear fuel at April 30, 2005 and 2004 was $373.4 million and $354.8 million, respectively.
Asset Retirement Obligation - The District adopted Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" (SFAS No. 143), on May 1, 2003. SFAS No. 143 requires the recognition and measurement of liabilities for legal obligations associated with the retirement of tangible long-lived assets. Under the standard, these liabilities are recognized at fair value as incurred and capitalized as part of the cost of the related tangible long-lived assets. Accretion of the liabilities, due to the passage of time, is an operating expense and the capitalized cost is depreciated over the useful life of the long-lived asset. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which a legal obligation exists under enacted laws, statutes, and written or oral contracts, including obligations arising under the doctrine of promissory estoppel.
The District has identified retirement obligations for the Palo Verde Nuclear Generating Station (PVNGS), Navajo Generating Station (NGS), Four Corners Generating Station and certain other assets. On May 1, 2003, the District recorded a liability of
$173.7 million for asset retirement obligations, including the accretion impacts, a $63.3 million increase in the carrying amount of the associated assets, a net decrease of $99.7 million in accumulated decommissioning liability related to the reversal of the previously recorded accumulated decommissioning and a charge to earnings as a cumulative effect of $10.7 million.
SRP 2005 ANNUAL REPORT 31
NOTES TO COMBINED FINANCIAL STATEMENTS April 30, 2005 and 2004 Amounts recorded under SFAS No. 143, are subject to various assumptions and determinations, such as determining whether an obligation exists to remove assets, estimating the fair value of the costs of removal, estimating when final removal will occur, and determining the credit-adjusted risk-free interest rates to be utilized on discounting future liabilities. Changes that may arise over time with regard to these assumptions and determinations will change amounts recorded in the future as expense for asset retirement obligations.
A summary of the asset retirement obligation activity of the District for the year ended April 30, 2005, is included below (in millions):
Balance, May 1, 2004 186.9 Accretion expense 11.6 Balance, April 30, 2005 198.5 In accordance with regulations of the Nuclear Regulatory Commission, the District maintains a trust for the decommissioning of PVNGS. Decommissioning funds of $150.1 million and $137.1 million, stated at market value, as of April 30, 2005 and 2004, respectively, are held in the trust and are classified as segregated funds in the accompanying Combined Balance Sheets.
Unrealized gains on decommissioning fund assets of $33.5 million and $30.2 million at April 30, 2005 and 2004, respectively, are included in deferred credits and other non-current liabilities in the accompanying Combined Balance Sheets.
Accounting for Energy Risk Management Activities - The District has an energy risk management program to limit exposure to risks inherent in normal energy business operations. The goal of the energy risk management program is to measure and minimize exposure to market risks, credit risks and operational risks. Specific goals of the energy risk management program include reducing the impact of market fluctuations on energy commodity prices associated with customer energy requirements, excess generation and fuel expenses, in addition to meeting customer pricing needs, and maximizing the value of physical generating assets. The District employs established policies and procedures to meet the goals of the energy risk management program using various physical and financial instruments, including forward contracts, futures, swaps and options.
Certain of these transactions are accounted for under Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended (SFAS No. 133). Under SFAS No. 133, derivatives are recorded in the balance sheet as either an asset or liability measured at their fair value. The standard also requires changes in the fair value of the derivative be recognized each period in current earnings or other comprehensive income depending on the purpose for using the derivative and/or its qualification, designation and effectiveness as a hedging transaction. Many of the District's contractual agreements qualify for the normal purchases and sales exception allowed under SFAS No. 133 and are not recorded at market value. (For further explanation of the effects of SFAS No. 133 on the District's financial results, see Note (3) Accounting for Derivative Instruments and Hedging Activities.)
Concentrations of Credit Risk - The use of contractual arrangements to manage the risks associated with changes in energy commodity prices creates credit risk exposure resulting from the possibility of nonperformance by counterparties pursuant to the terms of their contractual obligations. In addition, volatile energy prices can create significant credit exposure from energy market receivables and mark-to-market valuations. The District has a credit policy for wholesale counterparties, and continuously monitors credit exposures, routinely assesses the financial strength of its counterparties, minimizes credit risk by dealing primarily with creditworthy counterparties, entering into standardized agreements which allow netting of exposures to and from a single counterparty and by requiring letters of credit, parent guarantees or other collateral when it does not consider the financial strength of a counterparty sufficient.
Income Taxes - The District is exempt from federal and Arizona state income taxes. Accordingly, no provision for income taxes has been recorded for the District in the accompanying combined financial statements.
32 ISRP 2005 ANNUAL REPORT
NOTES TO COMBINED FINANCIAL STATEMENTS April 30, 2005 and 2004 The District has four wholly-owned taxable subsidiaries; New West Energy, CRS, PPC and Springerville Four. The tax effect of these subsidiaries' operations on the combined financial statements is immaterial.
Cash Equivalents - The District treats short-term temporary cash investments with original maturities of three months or less as cash equivalents.
Rate Stabilization Fund - On April 29, 2005, the District transferred $55million into the Rate Stabilization Fund to be used in concert with the Fuel and Purchased Power Adjustment Mechanism to cover fuel related expenses and to stabilize future prices related to fuel, as well as for any other purposes required or permitted by the Board's Supplemental Resolution dated September 10, 2001 authorizing an Amended and Restated Resolution Concerning Revenue Bonds (Bond Resolution), during fiscal years 2006 and 2007. (See Note (10) Regulatory Issues, The Changing Regulatory Environment, for additional information on the Rate Stabilization Fund.)
Revenue Recognition - The District recognizes revenue when billed and accrues estimated revenue for electricity delivered to customers that has not yet been billed. Other operating revenue consists primarily of revenue from marketing and trading electricity.
Materials and Supplies, and Fuel Stocks - Materials and supplies are stated at lower of market or average cost. Fuel stocks are stated at lower of market or weighted average cost.
Reclassifications - For comparative purposes, certain prior year amounts have been reclassified to conform to the current year presentation. The reclassifications had no impact on net revenues or cash flows.
Recently Issued Accounting Standards - FASB has issued the following Statement of Financial Accounting Standards (SFAS), Staff Positions (FSP), and Interpretations (FIN) that may have financial impacts on the District:
SFAS No. 132 (R), "Employers' Disclosures about Pensions and Other Postretirement Benefits" (SFAS No. 132 (R)), was issued in December of 2003 and replaces SFAS No. 132, "Employers' Disclosures about Pensions and Other Postretirement Benefits" (SFAS No. 132). This statement revises employers' disclosures about pension plans and other postretirement benefit plans.
The disclosures required beyond those in the original SFAS No. 132 include additional information regarding plan assets, the accumulated benefit obligations, projected benefit payments, estimated expected contributions, assumptions used in the calculations and the measurement date of the plans. It does not change the measurement or recognition of those plans. This statement is effective for financial statements with fiscal years ending after December 15, 2003 and interim periods beginning after December 15, 2003. The disclosure regarding estimated future benefit payments will be effective for fiscal years ending after June 15, 2004. The District has adopted the revised standard. (See Note (7) Employee Benefit Plans and Incentive Programs.)
FIN No. 46, "Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51" (FIN No. 46),
provides guidance on the identification and consolidation of entities for which control is achieved through means other than voting rights (variable interest entities). FIN No. 46 also requires additional disclosure describing transactions with variable interest entities in which consolidation is not required. In December 2003, the FASB revised FIN No. 46 (FIN No. 46R) to defer the implementation date for preexisting variable interest entities (VIEs) that are not special purpose entities (SPEs) until the end of the first interim or annual period ending after December 31, 2003. For VIEs that are not SPEs, companies must apply FIN No.
46R no later than the end of the first reporting period ending after March 15, 2004. SRP adopted FIN No. 46R as required.
The adoption did not have a material impact on the accompanying combined financial statements. (See also Notes (5) and (9) regarding the lease purchase of the Desert Basin Generating Station (Desert Basin).)
FSP 106-1 and FSP 106-2, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003" were released in January and May 2004, respectively. The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Act) was signed into law in December 2003 and establishes a prescription drug benefit, as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare's prescription drug coverage. FSP 106-2 provides guidance on the SRP 2005 ANNUAL REPORT 33
NOTES TO COMBINED FINANCIAL STATEMENTS April 30, 2005 and 2004 accounting for the effects of the Medicare Act for employers that sponsor postretirement health care plans that provide prescription drug benefits and requires those employers to provide certain disclosures regarding the effect of the federal subsidy provided by the Medicare Act. In August 2004, SRP retroactively adopted the provisions of FSP 106-2, resulting in the re-measurement of our postretirement benefit plans' accumulated postretirement benefit obligation as of May 1, 2004. The impact of the federal subsidy is a decrease in the accumulated projected benefit obligation of approximately $29.0 million and a decrease of approximately
$4.5 million in the net periodic postretirement benefit cost for fiscal year 2005.
(3) Accounting for Derivative Instruments and Hedging Activities:
The District follows SFAS No. 133, as amended, which requires that entities recognize all derivatives as either assets or liabilities in the balance sheet and measure those instruments at fair value. Changes in the fair value of derivative financial instruments are either recognized periodically in net revenues or accumulated net revenues (as a component of other comprehensive income),
depending on whether or not the derivative meets specific hedge accounting criteria. The criteria include a requirement for hedge effectiveness, which is measured based on the relative changes in fair value between the derivative contract and the hedged item over time. Changes in the fair value resulting from ineffectiveness are recognized immediately in net revenues.
The District enters into contracts for electricity, natural gas and other energy commodities to meet the expected needs of its retail customers. The District sells excess capacity during periods when it is not needed to meet retail requirements. The District's energy risk management program uses various physical and financial contracts to hedge exposures to fluctuating commodity prices.
The District examines contracts at inception to determine the appropriate accounting treatment. If a contract does not meet the derivative criteria, or if it qualifies for the SFAS No. 133 normal purchases and sales scope exception, the District accounts for the contract using settlement accounting (costs and revenues are recorded when physical delivery occurs). Contracts that qualify as a derivative but do not meet the SFAS No. 133 normal purchases and sales scope exception are further examined by the District to determine if they qualify for hedge accounting. If a contract does not meet the hedging criteria in SFAS No. 133, the District recognizes the changes in the fair value of the derivative instrument in net revenues each period (mark-to-market). If the contract does qualify for hedge accounting, changes in the fair value are recorded in accumulated net revenues and other comprehensive income (as a component of other comprehensive income).
The District formally documents all relationships between hedging instruments and hedged items, as well as its risk-management objective and strategy for undertaking various hedge transactions. This process includes linking all derivatives to the forecasted transactions. The District also formally assesses (both at the hedge's inception and on an ongoing basis) whether the derivatives used in hedging transactions have been effective in offsetting changes in cash flow of hedged items and whether those derivatives may be expected to remain effective in future periods. When it is determined that a derivative is not (or has ceased to be) effective as a hedge, the District discontinues hedge accounting prospectively, as discussed below.
The District discontinues hedge accounting when: (1) it determines that the derivative is no longer effective in offsetting changes in cash flows of a hedged item; (2) the derivative expires or is sold, terminated or exercised; (3) it is no longer probable that the forecasted transaction will occur; or (4) management determines that designating the derivative as a hedging instrument is no longer appropriate.
34 JSRP 2005 ANNUAL REPORT
NOTES TO COMBINED FINANCIAL STATEMENTS April 30, 2005 and 2004 When the District discontinues hedge accounting because it is no longer probable that the forecasted transaction will occur in the originally expected period, the gain or loss on the derivative is reclassified into net revenues. If the derivative remains outstanding, the District will carry the derivative at its fair value in the Combined Balance Sheets, recognizing changes in the fair value in current-period net revenues.
As of April 30, 2005 and 2004, the valuation of the District's energy risk management contracts resulted in an increase (decrease) in electric revenues of $(4.9) million and $7.3 million, respectively, and a decrease in fuel expenses of $40.1 million and $21.5 million, respectively. The impact to combined net revenues for fiscal years 2005 and 2004 was an unrealized gain of $35.2 million and $28.8 million, respectively. Accumulated net revenues and other comprehensive income (as a component of other comprehensive income) were unchanged as of April 30, 2005 and April 30, 2004. The following table summarizes the District's derivative-related assets and liabilities at April 30 (in thousands):
2005 2004 Other current assets 65,485 40,195 Deferred charges and other assets 65,915 41,020 Other current liabilities (37,900)
(37,783)
Deferred credits and other non-current liabilities (82,398)
(31,747)
Net asset 11,102 11,685 The electric industry engages in an activity called "book-out," under which some energy purchases are netted against sales, and power does not actually flow in settlement of the contract. As a result of these transactions, the District nets the impacts of these financially settled contracts, which reduced revenues and purchase power expense by $142.7 million and $91.2 million for fiscal years 2005 and 2004, respectively, but which did not impact net revenues or cash flows.
In November 2003, the FASB revised its derivative guidance on Issue No. C1 5, "Normal Purchases and Normal Sales Exception for Option-Type Contracts and Forward Contracts in Electricity." The new guidance, which is effective for the District on May 1, 2004, affects the criteria for the normal purchases and sales exception for purchase power and sales agreements. The implementation of this change did not impact its financial statements.
SRP 2005 ANNUAL REPORT135
NOTES TO COMBINED FINANCIAL STATEMENTS April 30, 2005 and 2004 (4) Accumulated Net Revenues and Other Comprehensive Income:
The following table summarizes accumulated net revenues and other comprehensive income (in thousands):
Accumulated Other Comprehensive Income (Loss)
Accumulated Net Revenues And Other Comprehensive Income Accumulated Net Revenues BALANCE, April 30, 2003 2,312,256 (108,328) 2,203,928 Net revenues 112,220 112,220 Minimum pension liability 48,500 48,500 Reclassification of realized loss to income (2,477)
(2,477)
Net unrealized gain on available-for-sale securities 19,219 19,219 BALANCE, April 30, 2004 2,424,476 (43,086) 2,381,390 Net revenues 362,450 362,450 Minimum pension liability (35,300)
(35,300)
Net unrealized gain on 6,021 6,021 available-for-sale securities BALANCE, April 30, 2005 2,786,926 (72,365) 2,714,561 The majority of net unrealized gain on available-for-sale securities originates from segregated fund investments. Net unrealized gain on available-for-sale securities consists of gross unrealized gain on equity funds of $6.0 million and $20.4 million, and gross unrealized gain (loss) on debt funds of $.02 million and $(1.2) million, at April 30, 2005 and 2004, respectively. Accumulated Other Comprehensive Income (Loss) consists of minimum pension liability of $(1 14,700) and $(79,400), and net unrealized gain on available-for-sale securities of $42,335 and $36,314, at April 30, 2005 and 2004, respectively.
(5) Long-Term Debt:
Long-term debt consists of the following at April 30 (in thousands):
Interest Rate 2005 2004 Revenue bonds (mature through 2032) 3.5-6.5%
$ 2,204,217 2,375,550 Unamortized bond (discount) premium 40,229 49,648 Total revenue bonds outstanding 2,244,446 2,425,198 Finance lease 2.0 - 5.3%
282,680 282,680 Commercial paper 2.0 - 3.1%
475,000 375,000 Total long-term debt 3,002,126 3,082,878 Less - current portion (274,778)
(170,029)
Total long-term debt, net of current portion
$ 2,727,348 2,91 2,849 36 ISRP 2005 ANNUAL REPORT
NOTES TO COMBINED FINANCIAL STATEMENTS April 30, 2005 and 2004 The annual maturities of long-term debt (excluding commercial paper and unamortized bond discount/premium) as of April 30, 2005, due in fiscal years ending April 30, are as follows (in thousands):
Revenue Bonds Finance Lease 2006 274,778 16,300 2007 115,046 16,015 2008 135,475 17,780 2009 153,297 16,790 2010 115,855 19,950 Thereafter 1,409,766 195,845
$ 2,204,217 282,680 Revenue Bonds - Revenue bonds are secured by a pledge of, and a lien on, the revenues of the electric system, after deducting operating expenses, as defined in the bond resolution. Under the terms of the amended and restated bond resolution, effective in January 2003, the District is no longer required to make monthly deposits to an externally trusteed debt service fund for the payment of future principal and interest. However, the District is continuing to make debt service deposits to a non-trusteed segregated fund. Included in segregated funds in the accompanying Combined Balance Sheets is $198.7 million and $164.5 million of debt service related funds as of April 30, 2005 and 2004, respectively.
The District has $52.1 million of mini-revenue bonds outstanding which are redeemable at the option of the bondholder under certain circumstances. Based on historical redemptions made on these bonds, management believes there are sufficient funds available to cover potential redemptions in any year.
The debt service coverage ratio, as defined in the bond resolution, is used by bond rating agencies to help evaluate the financial viability of the District. For the years ended April 30, 2005 and 2004, the debt service coverage ratio was 2.39 and 2.00, respectively.
Interest and the amortization of the bond discount, premium and issue expense on the various issues results in an effective rate of 5.03% over the remaining term of the bonds.
The District has authorization to issue additional Electric System Revenue Bonds totaling $1.2 billion principal amount and Electric System Refunding Revenue Bonds totaling $2.9 billion principal amount. No Electric System Revenue Bonds were issued in fiscal year 2005.
Finance Lease - In December 2003, the District entered into a lease-purchase agreement (Desert Basin Lease-Purchase Agreement) with Desert Basin Independent Trust (DBIT) to finance the acquisition of Desert Basin located in Central Arizona. In a concurrent transaction, $282.7 million in fixed-rate Certificates of Participation (COPs) were issued pursuant to a Trust Indenture, between Wilmington Trust Company, as trustee, and DBIT, to fund the acquisition of Desert Basin and other electric system assets of the District. Investors in the COPs obtained an interest in the lease payments made by the District to DBIT under the Desert Basin Lease-Purchase Agreement. Due to the nature of the Desert Basin Lease-Purchase Agreement, the District has recorded a lease-finance liability to DBIT with the same terms as the COPs.
In connection with the issuance of the COPs, the District entered into an interest rate swap transaction with Morgan Stanley Capital Services. This transaction consisted of a 6-year, $75 million fixed-to-floating swap (annual $25 million notional maturities expiring on December 1, 2007 through 2009, respectively) versus the Bond Market Association (BMA) Municipal Index.
SRP 2005 ANNUAL REPORT 37
NOTES TO COMBINED FINANCIAL STATEMENTS April 30, 2005 and 2004 The fixed-receiver rate on the swap is 3.001%. Through the swap, the District was able to create synthetic variable rate debt and take advantage of the relationship between intermediate-term, tax-exempt borrowing costs and BMA-based, fixed-receiver swap rates. In addition, the swap to variable rate also enables the District to increase its short-term, variable rate debt portfolio. The interest rate swap is accounted for as a derivative and qualifies for hedge accounting. (For further explanation of the effects of SFAS No. 133 on the District's financial results see Note (3) Accounting for Derivative Instruments and Hedging Activities.)
Commercial Paper - The District has outstanding $475.0 million of commercial paper consisting of $375.0 million Series B Commercial Paper and as of December 2004, $100 million Series C Commercial Paper. The issues have an average weighted interest rate to the District of 2.28%.
The commercial paper matures not more than 270 days from the date of issuance and is an unsecured obligation of the District.
The District has the ability to refinance the outstanding commercial paper on a long-term basis in connection with its revolving line of credit that supports the commercial paper and is available through December 7, 2009. As such, the District has classified the commercial paper as long-term debt in the Combined Balance Sheets as of April 30, 2005.
While the revolving credit agreement contains covenants that could prohibit borrowing under certain conditions, management believes financing would be available. The District has never borrowed under the agreement and management does not expect to do so in the future. Alternative sources of funds to support the commercial paper program include existing funds on hand or the issuance of alternative debt, such as revenue bonds.
Line-of-Credit Agreements - The District has a $475.0 million revolving line-of-credit agreement that supports the $475.0 million commercial paper program. The agreement has various covenants, with which the District was in compliance at April 30, 2005.
(6) Fair Value of Financial Instruments:
The following methods and assumptions were used to estimate the fair value of each class of financial instruments identified in the following items in the accompanying Combined Balance Sheets.
Investments in Marketable Securities - The District invests in U.S. government obligations, certificates of deposit and other marketable investments. Such investments are classified as other investments, segregated funds, cash and cash equivalents or temporary investments in the accompanying Combined Balance Sheets depending on the purpose and duration of the investment.
The fair value of marketable securities with original maturities greater than one year is based on published market data. The carrying amount of marketable securities with original maturities of one year or less approximates their fair value because of their short-term maturities.
Long-Term Debt - The fair value of the District's revenue bonds, including the current portion, was estimated by using pricing scales from independent sources. The carrying amount of commercial paper approximates the fair value because of its short-term maturity.
Other Current Assets and Liabilities - The carrying amounts of receivables, accounts payable, customers' deposits and other current liabilities in the accompanying Combined Balance Sheets approximate fair value because of their short-term maturities.
The estimated carrying amounts and fair values of the District's financial instruments, at April 30, are as follows (in thousands):
2005 2004 Carrying Amount Fair Value Carrying Amount Fair Value Investments in marketable securities:
Other investments 35,765 35,406 50,910 50,787 Segregated funds 621,518 622,100 535,944 537,344 Rate Stabilization Fund 55,000 55,000 Temporary investments 135,081 134,822 60,750 60,750 Long-term debt 3,020,526 3,143,934 3,103,367 3,151,902 38 ISRP 2005 ANNUAL REPORT
NOTES TO COMBINED FINANCIAL STATEMENTS April 30, 2005 and 2004 Accounting for Debt and Equity Securities - The District's investments in debt securities are reported at amortized cost if the intent is to hold the security to maturity. At April 30, 2005, the District's investments in debt securities have maturity dates ranging from May 20, 2005 to February 28, 2012. Other debt and equity securities are reported at market, with unrealized gains or losses included as a separate component of Accumulated Net Revenues and Other Comprehensive Income. The District's investments in debt and equity securities are included in temporary investments, segregated funds and non-utility property and other investments in the accompanying Combined Balance Sheets.
(7) Employee Benefit Plans and Incentive Programs:
Defined Benefit Pension Plan and Other Postretirement Benefits - SRP's Employees' Retirement Plan (the Plan) covers substantially all employees. The Plan is funded entirely from SRP contributions and the income earned on invested Plan assets. The District made a contribution of $75.0 million and $10.0 million in fiscal years 2005 and 2004, respectively.
SRP provides a non-contributory defined benefit medical plan for retired employees and their eligible dependents (contributory for employees hired January 1, 2000 or later) and a non-contributory defined benefit life insurance plan for retired employees.
Employees are eligible for coverage if they retire at age 65 or older with at least five years of vested service under the Plan (ten years for those hired January 1, 2000 or later), or any time after attainment of age 55 with a minimum of ten years of vested service under the Plan (20 years for those hired January 1, 2000 or later). The funding policy is discretionary and is based on actuarial determinations. The unrecognized transition obligation is being amortized over 20 years, beginning in 1994.
The following tables outline changes in benefit obligations, plan assets, the funded status of the plans and amounts included in the combined financial statements as of April 30, based on January 31 valuation dates (in thousands):
Pension Benefits Postretirement Benefits 2005 2004 2005 2004 Change in benefits obligation:
Benefit obligation at beginning of year $
889,000 779,000 392,700 312,000 Service cost 27,100 22,600 8,800 8,500 Interest cost 54,600 51,600 22,500 22,900 Actuarial loss 82,200 68,600 30,400 59,700 Benefits paid (35,900)
(32,800)
(12,200)
(10,400)
Benefit obligations at end of year
$ 1,017,000 889,000 442,200 392,700 Change in plan assets:
Fair value of plan assets at beginning of year 670,000 545,600 Actual return on plan assets 76,200 157,200 Employer contributions 85,000 12,200 10,500 Benefits paid (35,900)
(32,800)
(12,200)
(10,500)
Fair value of plan assets at end of year 795,300 670,000 SRP 2005 ANNUAL REPORT 139
NOTES TO COMBINED FINANCIAL STATEMENTS April 30, 2005 and 2004 Pension Benefits Postretirement Benefits 2005 2004 2005 2004 Funded status (221,700)
(219,000)
(442,200)
(392,700)
Unrecognized transition obligation 32,900 37,000 Unrecognized net actuarial loss 270,200 214,800 184,600 162,000 Unrecognized prior service cost 20,300 22,800 500 600 Post January 31 contributions 10,000 3,100 2,900 Net asset (liability) recognized 68,800 28,600 (221,100)
(190,200)
Amounts recognized in Combined Balance Sheets:
Prepaid benefit cost 68,800 28,600 Additional minimum liability (135,000)
(102,200)
Net additional minimum liability (66,200)
(73,600)
Accrued benefit liability (221,100)
(190,200)
'Intangible asset 20,300 22,800 Accumulated other 114,700 79,400 comprehensive income Net asset (liability) recognized 68,800 28,600 (221,100)
(190,200)
The following table outlines the projected benefit obligation and accumulated benefit obligation in excess of Plan assets as of April 30, based on January 31 valuation dates (in thousands):
2005 2004 Projected benefit obligation Accumulated benefit obligation Fair value of Plan assets 1,017,000 861,500 795,300 889,000 753,600 670,000 The District internally funds its other postretirement benefits obligation. At April 30, 2005 and 2004, $253.9 million and $196.1 million of segregated funds, respectively, were designated for this purpose.
The weighted average assumptions used to calculate actuarial present values of benefit obligations at April 30 were as follows:
Pension Benefits Postretirement Benefits 2005 2004 2005 2004 Discount rate 5.75%
6.25%
5.75%
6.25%
Rate of compensation increase 4.0%
4.0%
4.0%
4.0%
The weighted average assumptions used to calculate net periodic benefit costs were as follows:
Pension Benefits Postretirement Benefits Discount rate Expected return on Plan assets Rate of compensation increase 40 ISRP 2005 ANNUAL REPORT 2005 6.25%
7.75%
4.0%
2004 6.75%
8.25%
4.0%
2005 2004 6.25%
6.75%
N/A N/A 4.0%
4.0%
NOTES TO COMBINED FINANCIAL STATEMENTS April 30, 2005 and 2004 For employees who retire at age 65 or younger, for measurement purposes, a 9.0% annual increase before attainment of age 65 and 11.0% annual increase on and after attainment of age 65 in per capita costs of health care benefits were assumed during 2005; these rates were assumed to decrease uniformly until equaling 5.0% in all future years.
Components of net periodic benefit (gain) costs for the years ended April 30, are as follows (in thousands):
Pension Benefits Postretirement Benefits 2005 2004 2005 2004 Service cost 27,100 22,500 8,800 8,500 Interest cost 54,600 51,600 22,500 22,900 Expected return on Plan assets (57,000)
(57,700)
Amortization of transition obligation 4,100 4,100 Recognized net actuarial loss 7,600 7,800 8,300 Amortization of prior service cost 2,500 2,700 100 Net periodic benefit cost 34,800 19,100 43,300 43,800 Assumed health care cost trend rates have a significant effect on the amounts reported for health care plans. A one-percentage-point change in the assumed health care cost trend rates would have the following effect (in thousands):
One-Percentage-Point Increase Effect on total service cost and interest cost components 5,200 Effect on postretirement benefit obligation 66,000 One-Percentage-Point Decrease (4,500)
(58,600)
Plan Assets - The Board has established an investment policy for Plan assets and has delegated oversight of such assets to a compensation committee (the Committee). The investment policy sets forth the objective of providing for future pension benefits by targeting returns consistent with a stated tolerance of risk. The investment policy is based on analysis of the characteristics of the Plan sponsors, actuarial factors, current Plan condition, liquidity needs, and legal requirements. The primary investment strategies are diversification of assets, stated asset allocation targets and ranges, and external management of Plan assets. The Committee determines the overall target asset allocation ratio for the Plan and defines the target asset allocation ratio deemed most appropriate for the needs of the Plan and the risk tolerance of the District.
The Plan's weighted-average asset allocations at April 30, based on January 31 valuations, are as follows:
Equity securities Debt securities Real estate Total Target Allocations 65.0%
25.0%
10.0%
100.0%
2005 65.8%
25.2%
9.0%
100.0%
2004 67.2%
22.8%
10.0%
100.0%
The investment policy allows for a tolerance range of plus or minus 5% from the stated target asset allocation.
SRP 2005 ANNUAL REPORT 141
NOTES TO COMBINED FINANCIAL STATEMENTS April 30, 2005 and 2004 Long-Term Rate of Return - The expected return on Plan assets is based on a review of the Plan asset allocations and consultations with a third-party investment consultant and the Plan actuary, considering market and economic indicators, historical market returns, correlations and volatility, and recent professional or academic research. As history has demonstrated, markets may decline and increase dramatically; however, the expected rate of return on the Plan assets is reasonable given its asset allocation in relation to historical and expected future performance.
Employer Contributions - The District expects to contribute $60 million to the Plan over the next valuation period.
Benefits Payments - The District expects to pay benefits in the amounts as follows (in thousands):
2006 34,900 2007 37,000 2008 39,700 2009 43,000 2010 46,600 2011 through 2015 289,300 Defined Contribution Plan - SRP's Employees' 401 (k) Plan (the 401 (k) Plan) covers substantially all employees. The 401 (k)
Plan receives employee pre-tax and post-tax contributions and partial employer matching contributions. Employer matching contributions to the 401 (k) Plan were $9.7 million and $9.1 million during fiscal years 2005 and 2004, respectively.
Employee Incentive Compensation Program - SRP has an incentive compensation program covering substantially all regular employees. The incentive compensation amount is based on achievement of pre-established targets. An accrual of $26.4 million and $24.7 million for fiscal years ended April 30, 2005 and 2004, respectively, is included in other current liabilities in the accompanying Combined Balance Sheets. This liability is stated net of receivables from participants in jointly-owned electric plants of $2.7 million and $2.4 million at April 30, 2005 and 2004, respectively.
(8) Interests in Jointly-Owned Electric Utility Plants:
The District has entered into various agreements with other electric utilities for the joint ownership of electric generating and transmission facilities. Each participating owner in these facilities must provide for the cost of its ownership share. The District's share of expenses of the jointly-owned plants is included in operating expenses in the accompanying Combined Statements of Net Revenues.
The following table reflects the District's ownership interest in jointly-owned electric utility plants as of April 30, 2005 (in thousands):
Ownership Plant in Accumulated Construction Work Generating Station bnare Service Uepreciation in Progress Four Corners (NM) (Units 4 & 5) 10.00%
103,601 (92,836) 5,759 Mohave (NV) (Units 1 & 2) 20.00%
131,900 (123,146) 10 Navajo (AZ) (Units 1, 2 & 3) 21.70%
346,906 (253,929) 10,279 Hayden (CO) (Unit 2) 50.00%
115,424 (78,538) 440 Craig (CO) (Units 1 & 2) 29.00%
262,465 (152,826) 4,257 PVNGS (AZ) (Units 1, 2 & 3) 17.49%
1,239,219 (857,450) 40,545 2,199,515
$ (1,558,725) 61,290 42 ISRP 2005 ANNUAL REPORT
NOTES TO COMBINED FINANCIAL STATEMENTS April 30, 2005 and 2004 (9) Finance Lease:
In October 2003, the District acquired a 100% interest in Desert Basin plant from Reliant Energy Desert Basin, LLC (Reliant) for $282.5 million and assumed operations, thereby terminating the long-term purchase power agreement with Reliant and the District's capital lease asset and obligation. The purchase was financed through the Desert Basin Lease-Purchase Agreement, via a transfer of the assets to DBIT, and the issuance of COPs. (For further explanation of the Desert Basin Lease-Purchase Agreement see Note (5)
Long-Term Debt.) The District will continue to operate Desert Basin at its own risk through the term of the lease-purchase agreement and upon transfer of ownership to the District at the end of the lease term. Continuing involvement in Desert Basin precluded the use of sale-leaseback accounting. GAAP requires the District to report the proceeds under the Desert Basin Lease-Purchase Agreement as a liability, continue to report the facility as a utility plant asset, and continue to depreciate the property. The sales proceeds have been recorded as a liability of $282.7 million and are included in long-term debt in the accompanying Combined Balance Sheets as of April 30, 2005 and April 30, 2004.
(10) Regulatory Issues:
Fundamental Changes in the Electric Utility Industry - The District historically operated in a highly regulated environment in which it had an obligation to deliver electric service to customers within its service area. In 1998, the Arizona Electric Power Competition Act (the Act) authorized competition in the retail sales of electric generation, recovery of stranded costs and competition in billing, metering and meter reading.
Similarly, in 1999, the Arizona Corporation Commission (the Commission), which regulates public service corporations, approved final rules for retail electric competition.
While retail competition was available to all customers by 2001, there were only a few customers who chose an alternative energy provider. Those customers have since returned to their incumbent utilities. At this time, there is no active retail competition within the District's service territory or, to the knowledge of the District, within the State of Arizona.
As provided for in the Act, the District assessed a temporary surcharge on electric distribution service prices to pay for all or a portion of unmitigated stranded costs of electric generation service incurred as a direct result of the onset of competition. The Act required that such costs, in order to be recovered, must have been incurred to serve customers in Arizona before December 26, 1996, and that the surcharge must not have caused prices to exceed the prices that were in effect on December 30, 1998. Effective June 1, 2004, the District ceased collection of this surcharge.
In January 2004, the Arizona Court of Appeals found numerous provisions of the Commission's retail electric competition rules to be invalid. Specifically, the court concluded that the Certificates of Convenience and Necessity awarded by the Commission to fifteen competitive electric service providers were invalid due to the Commission's failure to determine the fair value of the utilitys Arizona property in setting rates. Other rules affected included the requirement to create an independent scheduling administrator and billing and collection practices. One of the plaintiffs in the action, Trico Electric Cooperative, Inc., filed a petition for review with the Arizona Supreme Court. The court denied the petition for review in January 2005. At this time, the Commission has taken no action to modify its electric competition rules to address the ruling of the Court of Appeals.
The Federal Energy Regulatory Commission (FERC) regulates the electric utility industry under the authority of various statutes.
FERC issued rules in 1996 mandating, among other things, open nondiscriminatory access to transmission lines. The rules require comparable transmission service in order to use the transmission systems of utilities under FERC jurisdiction (jurisdictional utilities).
The District has filed a comparable open access transmission tariff to ensure reciprocal access, pursuant to rules FERC developed for non-jurisdictional utilities like the District. Also, FERC has issued procedures for jurisdictional utilities that own, control or operate electric transmission facilities to use for interconnecting generating facilities. The District jointly owns with jurisdictional utilities certain transmission facilities, which arguably would be subject to FERC's rules.
SRP 2005 ANNUAL REPORT 143
NOTES TO COMBINED FINANCIAL STATEMENTS April 30, 2005 and 2004 In December 1999, FERC issued its Order No. 2000, which, among other things, created a collaborative process for utilities to facilitate the creation of regional transmission organizations (RTOs). FERC encouraged participation in RTOs by non-public utilities.
The District is participating in a number of voluntary, cost-effective initiatives designed to enhance the wholesale market in the West.
The District is working cooperatively with other organizations and market participants in the Western Interconnection to coordinate and implement the enhancements on a brood regional basis.
The Changing Regulatory Environment - The District has fully opened its service area to competition in generation and billing, metering and meter reading. The District's electric distribution area remains regulated by its Board and the District will not provide distribution services in the distribution areas of other utilities.
The District's price plans have been unbundled since 1999. The Board approved a 1.5% overall price increase for the District that became effective on November 1, 2004. Certain changes to the various components of the existing price plans took effect on June 1, 2004, but had no impact on the overall price levels. Among other things, the Board approved a new Fuel and Purchased Power Adjustment Mechanism that permits the District to implement automatic changes in this mechanism on a seasonal basis subject to a 2-mill dead-band and implemented a Transmission Cost Adjustment Factor. The Fuel and Purchased Power Adjustment Mechanism provides for a true-up between related costs and expenses every six months and provides for the prospective collection of amounts for fuel and purchase power costs above predetermined levels. The Transmission Cost Adjustment Factor provides for a collection of new costs resulting from the establishment of regional or other entities to oversee transmission operations, regional planning and wholesale markets for electricity or the establishment of new operating rules for wholesale markets. The District prices its electric generation based upon market and cost of service factors.
The Board has approved two fuel and purchased power increases under the new Fuel and Purchased Power Adjustment Mechanism.
The first change increased annual bills by an amount of 3.7% and became effective coincident with the November 1, 2004 price increase. The second increase, approved in April 2005, became effective for the fiscal year beginning May 1, 2005, and will increase customer bills on average by 1.3%. The Rate Stabilization Fund that was created in April 2005 will be used in concert with the Fuel and Purchased Power Adjustment Mechanism to stabilize future prices related to fuel during the upcoming fiscal years 2006 and 2007. (See Note (2) Significant Accounting Policies, Rate Stabilization Fund, for additional information on the Rate Stabilization Fund.)
Since December 31, 1998, the District has been recovering stranded costs through a competitive transition charge (CTC) paid by all distribution customers. In fiscal year 2001 management determined, based upon projections using current economic conditions that the full CTC of $795.0 million might not be collected. Management, therefore, reduced the amount of the CTC asset and took a charge to depreciation and amortization expense of $85.0 million as of April 30, 2001. Further, as part of the November 2001 price plans review, the District reviewed the level of its CTC associated with stranded cost recovery and elected to retain the CTC at its current level until June 1, 2004. The remaining $10.6 million, recorded as a current asset as of April 30, 2004, was fully collected in May 2004. Effective June 2004, the District stopped collecting the CTC.
Through a surcharge to the District's transmission and distribution customers, the District recovers the costs of programs benefiting the general public, such as discounted rates for the elderly or impoverished, efficiency programs, demand-side management measures, renewable energy programs, economic development, research and development and nuclear decommissioning, including the cost of spent fuel storage. In its recent pricing approval, the Board approved additional funding for renewable energy programs, energy efficiency and energy conservation. These surcharges continue to be separately identified and included in the District's price plans for the regulated portion of its operations.
Regulatory Accounting - The District accounts for the financial effects of the regulated portion of its operations in accordance with the provisions of SFAS No. 71, which requires cost-based, rate-regulated utilities to reflect the impacts of regulatory decisions in their financial statements.
44 1SRP 2005 ANNUAL REPORT
NOTES TO COMBINED FINANCIAL STATEMENTS April 30, 2005 and 2004 As a result of the Board actions in August 1998 to open the District's service area to competition in generation, the District discontinued the application of SFAS No. 71 to its electric generation operations in fiscal year 1999. From that time forward, the provisions of SFAS No. 101, "Regulated Enterprises: Accounting for the Discontinuation of Application of FASB Statement No. 71," have been applied to the portion of its business no longer meeting the provisions of SFAS No. 71.
In fiscal year 1999, the District evaluated the carrying amounts of its generation operations in relation to future cash flows, expected to be generated from their use in a competitive environment, and determined that $850.2 million of these assets were impaired.
Impairment of $631.8 million was attributable to generation operations, and $163.7 million was attributable to long-term energy contracts. Of the total impairment, a maximum of $795.0 million could be recovered through the CTC, and such amount was recorded as a regulatory asset (CTC regulatory asset). The CTC regulatory asset was recovered through the competitive transition charge over the period beginning December 31, 1998, and continuing through May 31, 2004. Since December 31, 1998, the District has amortized or charged $784.9 million of the CTC asset to depreciation and amortization expense and recovered $758.3 million through CTC revenue.
Regulatory assets for spent nuclear fuel storage are amortized over the life of the nuclear plant. Bond defeasance regulatory assets are amortized over different periods, beginning in fiscal year 1997 and ending in fiscal year 2031. Regulatory assets are included in deferred charges and other assets on the accompanying Combined Balance Sheets.
Mohave Generating Station - The District and the other Participants in the Mohave Generating Station ("Mohave") entered into a settlement with the Sierra Club that requires the installation of certain pollution abatement equipment by the end of 2005 if the plant will continue to be operated as a coal-fired electric generating facility. (See Note (12) Contingencies, for additional information on air quality issues.) In addition, the initial term of the agreement to supply coal to Mohave will expire at the end of 2005 and the Hopi Tribe has demanded that the pumping of water for the slurry pipeline serving Mohave cease. The Mohave Participants have refused to commit to install pollution abatement equipment without reasonable assurance that water will be available to enable the delivery of coal to the plant. Consequently, the plant will cease operations at the end of 2005 for some extended period of time. The federal government and other interested parties have executed a memorandum of understanding whereby the Mohave Participants are providing funding toward a feasibility study and environmental report for an alternative water supply. The District has included approximately $113.0 million in its Capital Improvement Program to cover the costs of such equipment or alternate resources, if necessary. Although the Mohave Participants and the Hopi Tribe are trying to reach a settlement, it is not certain if, and when, a resolution will be reached. The District has already replaced a portion of the energy and is considering several options for replacing the balance of the capacity in the event of a prolonged shutdown.
SRP 2005 ANNUAL REPORT 45
NOTES TO COMBINED FINANCIAL STATEMENTS April 30, 2005 and 2004 If the negotiations are not successful and the Mohave Participants are unable to secure the extension of the life of Mohave, the Board has authorized the recovery of the balance of the District's investment in Mohave in its revenue requirements over the remainder of the scheduled useful life of the plant. Consequently, it was determined that the plants carrying value would not be realized through future revenues and a write-down of its carrying value of $66.2 million was recorded in fiscal year ended April 30, 2003, and an additional $5.2 million and $6.6 million of impairment was recorded in fiscal years 2005 and 2004, respectively. In accordance with accounting standards for rate-regulated enterprises (SFAS No. 71 ), a regulatory asset was established for $78.0 million, based on the District's expectation that any un-recovered book value at the end of 2005 would be recovered in future rates.
Deferred Charges and Deferred Credits - Deferred charges and other assets consist primarily of the following at April 30 (in thousands):
2005 2004 Bond defeasance regulatory asset 93,023 98,278 Mohave Generating Station regulatory asset 78,006 72,836 Spent nuclear fuel storage regulatory asset 22,210 22,830 Derivatives market valuation 65,915 41,020 Pension intangible asset 20,300 22,800 Other 42,819 46,213 322,273 303,977 If events were to occur making full recovery of these regulatory assets no longer probable, the District would be required to write off the remaining balance of such assets as a one-time charge to net revenues.
Deferred credits and other non-current liabilities consist primarily of the following at April 30 (in thousands):
2005 2004 Asset retirement obligation 198,450 186,921 Accrued postretirement benefit liability 221,100 190,200 Additional pension minimum liability 66,200 73,600 Accrued decommissioning costs 33,527 30,232 Provision for contract losses 79,619 92,900 Derivatives market valuation 82,398 31,747 Accrued spent nuclear fuel storage 24,486 25,328 Accrued environmental issues 76,959 80,348 Other 57,335 47,027 840,074 758,303 (11) Commitments:
Subsidiary Guarantees - The District acts as guarantor for New West Energy's contractual obligations as necessary to satisfy performance security requirements under agreements with utility distribution companies, brokers and counterparties for financial hedge transactions and power purchasers and sellers. No payments were made under these guarantees during fiscal years 2005 and 2004. Existing guarantees were terminated May 31, 2003, and New West Energy has not entered into any agreements since then.
Improvement Program - The Improvement Program represents the District's six-year plan for major construction projects and capital expenditures for existing generation, transmission, distribution and irrigation assets. For the 2006-2011 time period, the District estimates capital expenditures of approximately $4.2 billion. Major construction projects include possible construction of an additional unit at Springerville Generating Station, completion of the Santan Generating Station and other key generation, distribution and transmission projects.
46 ISRP 2005 ANNUAL REPORT
NOTES TO COMBINED FINANCIAL STATEMENTS April 30, 2005 and 2004 Long-Term Power Contracts - The District entered into three contracts, collectively, with the United States Bureau of Reclamation (United States), the Western Area Power Administration and the Central Arizona Water Conservation District (CAWCD) for the long-term sale, through September 2011, of power and energy associated with the United States' entitlement to NGS. The amount of energy available to the District varies annually and is expected to decline over the life of the contracts. The District pays a fixed amount under the contracts, pays the cost of NGS generation and other related costs and supplies energy at cost to CAWCD for Central Arizona Project facilities. The fixed portion of the District's payment obligations under the three contracts totals $47.0 million annually through fiscal year 2010, and $66.5 million thereafter. Of the total obligation, $25.2 million annually through fiscal year 2010 and $35.7 million thereafter are unconditionally payable regardless of the availability of power. Payments under these contracts totaled $86.3 million and $65.3 million in fiscal years 2005 and 2004, respectively.
The District entered into two other long-term power purchase agreements to obtain a portion of its projected load requirements through 2011. Minimum payments under these contracts are $41.5 million annually through fiscal year 2010 and $34.8 million thereafter.
Total payments under these two contracts, including the minimum payments, were $66.4 million and $66.1 million in fiscal years 2005 and 2004, respectively. In conjunction with the impairment analysis performed on generation-related operations, the District has recorded provisions for losses on these contracts. The provisions recorded in August 1998, of $163.7 million, are being amortized over the life of the contracts, commencing January 1, 1999. Amortization of $13.3 million has been reflected as a reduction in purchased power expense in fiscal years 2005 and 2004. The remaining liability at April 30, 2005 of $79.6 million is included in deferred credits and other non-current liabilities in the Combined Balance Sheets.
Fuel Supply - At April 30, 2005, minimum payments under long-term coal supply contract commitments are estimated to be $180.6 million in fiscal year 2006, $161.9 million in fiscal year 2007, $150.8 million in fiscal year 2008, $150.8 million in fiscal year 2009,
$150.8 million in fiscal year 2010 and $660.9 million thereafter.
(112) Contingencies:
Nuclear Insurance - Under existing law, public liability claims arising from a single nuclear incident are limited to $10.8 billion.
PVNGS Participants insure for this potential liability through commercial insurance carriers to the maximum amount available ($300.0 million) with the balance covered by an industry-wide retrospective assessment program as required by the Price-Anderson Act. If losses at any nuclear power plant exceed available commercial insurance, the District could be assessed retrospective premium adjustments. The maximum assessment per reactor per nuclear incident under the retrospective program is $100.6 million including a 5% surcharge, applicable in certain circumstances, but not more than $10.0 million per reactor may be charged in any one year for each incident.
Based on the District's ownership share of PVNGS, the maximum potential assessment would be $52.8 million, including the 5%
surcharge, but would be limited to $5.2 million per incident in any one year.
Spent Nuclear Fuel - Under the Nuclear Waste Policy Act of 1982, the District pays $0.001 per kWh on its share of net energy generation at PVNGS to the U. S. Department of Energy (DOE). The DOE was responsible for the selection and development of repositories for permanent storage and disposal of spent nuclear fuel not later than December 31, 1998. Because of the significant delays in the DOE's schedule, it cannot be determined when the DOE will accept waste from PVNGS or from the other owners of spent nuclear fuel. It is unlikely, due to PVNGS' position in DOE's queue for receiving spent fuel, that Arizona Public Service Company (APS), the operating agent of PVNGS, will be able to initiate shipments to DOE during the licensed life of PVNGS. Accordingly, APS has constructed an on-site dry cask storage facility to receive and store PVNGS spent fuel that is sufficient to provide storage for all three units for a 40-year operating life. The facility stored its first cask in March 2003. Twenty-eight casks are now stored on site.
The District's share of on-site interim storage at PVNGS is estimated to be $31.6 million for costs to store spent nuclear fuel from inception of the plant through fiscal year-end 2005, and $1.8 million per year going forward. These costs have been included in the District's regulated operations price plans for transmission and distribution.
SRP 2005 ANNUAL REPORT147
NOTES TO COMBINED FINANCIAL STATEMENTS April 30, 2005 and 2004 Black Mesa Litigation - Navajo Nation v. Peabody (U.S. Dist. Court, D.C. District) - In June 1999, the Navajo Nation filed a lawsuit in the United States District Court in Washington D.C. (the "U.S. District Court"), alleging that the coal supplier for the Navajo and Mohave Generating Stations (Peabody Coal Company), Southern California Edison Company (manager of the Mohave Generation Station ("MGS")), the District (manager of the Navajo Generating Station) and three individual defendants, had induced the United States to breach its fiduciary duty to the Navajo Nation and had violated federal racketeering statutes. The lawsuit arises out of negotiations that culminated in 1987 with amendments to the coal royalty and lease agreements for mining coal for the Navajo and Mohave Generating Stations. The suit alleges $600.0 million in damages. The plaintiffs also seek treble damages against the corporate defendants, including the District, measured by any amounts awarded under the racketeering statutes. In addition, the plaintiffs claim punitive damages of not less than $1.0 billion. In March 2001, the Hopi Tribe intervened in the suit. However, the claims of both the Navajo Nation and the Hopi Tribe have been dismissed in their entirety with respect to the District. The Navajo Nation and the Hopi Tribe may appeal the dismissals.
On February 9, 2005, the U.S. District Court granted a motion to stay the litigation until further order of the court. The Navajo Nation, the Hopi Tribe, Peabody and the Participants in both Mohave and NGS are in mediation with respect to this litigation and related business issues.
Navajo Nation v. United States (Court of Federal Claims) - Previously, the Navajo Nation had filed a lawsuit against the United States Government based on similar allegations. The lawsuit was dismissed, but on appeal, it was reinstated and the Court of Appeals, in August 2001, held that the United States had breached its fiduciary duty to the Navajo Nation, and that a claim for damages was within the jurisdiction of the Court of Federal Claims. Subsequently, the United States Supreme Court, in March 2003, reversed the decision of the Court of Appeals and remanded the case to the Court of Appeals for further proceedings consistent with its opinion. In October 2003, the Court of Appeals remanded the case to the Court of Federal Claims and ordered that court to determine if the Navajo Nation had waived any claims with respect to statutes and regulations other than those the Court of Appeals concluded were at issue before the Supreme Court. If the Court of Federal Claims determines that there was not a waiver, it will determine if such other statutes and regulations impose enforceable fiduciary duties upon the United States in connection with Peabody's leases and, if so, whether the United States breached such duties.
Peabody Legal Fees Cases - Peabody claims it is entitled to reimbursement under the coal supply agreements for its costs associated with the defense of the Navajo Nation and Hopi Tribe's challenge of the coal leases (see above matters). Peabody has filed two separate lawsuits against the NGS and MGS Participants, respectively, seeking recovery of these fees. The MGS and NGS Participants dispute Peabody's attempt to recover its legal costs under the coal supply agreements. As for the MGS fees, the District has been dismissed from the litigation and awarded its attorneys fees. Peabody is appealing this dismissal. In the NGS fees case, the District and the NGS Participants received a favorable ruling dismissing all of Peabody's claims for reimbursement.
Peabody is likely to appeal this ruling.
Peabody v. SRP - Peabody has also filed suit in St. Louis, Missouri against the District and the other owners of NGS asserting claims against both the Participants and against the District relating to liability issues associated with the Navajo Nation Lawsuit, alleged breach of the NGS Coal Supply Agreement and breach of indemnity obligations owed to Peabody as the alleged agent of the NGS Participants, and claims of tortuous interference with contracts and tortuous interference with business expectancies against the District. The claim seeks $500 million and unspecified compensatory damages, prejudgment interest, attorneys' fees and costs.
The District is unable to predict the likely outcome of these matters at this time but does not believe that these disputes will have material adverse effects on its operations or financial condition.
Environmental - SRP is subject to numerous legislative, administrative and regulatory requirements relative to air quality, water quality, hazardous waste disposal and other environmental matters. SRP conducts ongoing environmental reviews of its properties for compliance and to identify those properties it believes may require remediation. Such requirements have resulted, and will continue to result, in increased costs associated with the operation of existing properties.
48 ISRP 2005 ANNUAL REPORT
NOTES TO COMBINED FINANCIAL STATEMENTS April 30, 2005 and 2004 In September 2003, the District received notice from the U.S. Environmental Protection Agency (EPA) that it is potentially liable under the Comprehensive Environmental Response, Compensation and Liability Act as an owner and operator of a facility (the 161h St. facility) within the Motorola 52nd Street Superfund Site. The District is potentially liable for past costs incurred and for future work to be conducted within the Superfund Site. Investigation and evaluation of this potential liability are in the preliminary stages and the District is unable at this time to predict the outcome, but believes that it has adequate reserves for this potential liability.
The EPA is continuing its national enforcement initiative under the New Source Review ("NSR") provisions of the Clean Air Act (CAA). This initiative is focused on determining whether companies had failed to disclose major repairs or alterations to facilities that have required the installation of new pollution control equipment. As part of this initiative, the District received three (3) letters from Region IX of the EPA, under the authority of Section 114 of the CAA, requesting information on Coronado Generating Station (CGS) (the "Section 114 Letters"). However, in March 2004, the EPA suspended its last request to enter into negotiations with the District regarding possible additional control technology to reduce emission levels from District generating units. To date, EPA Region IX has taken no enforcement action against the District for alleged violations of NSR regulations at CGS. The District is unable to predict the outcome of the Section 114 Letters or negotiations with EPA Region IX with respect to potential impacts on District generating units, but is optimistic that it will reach a mutually satisfactory agreement with the EPA regarding control technology and emission limits at District facilities.
Several species listed under the Endangered Species Act ("ESA") have been discovered in and around Roosevelt and Horseshoe Dams. To obtain an Incidental Take Permit ("ITP") under the ESA, the District entered into formal consultation with the United States Fish and Wildlife Service ("USFWS"), and developed a Habitat Conservation Plan ("Plan"), which allows full operation of Roosevelt Dam and reservoir, provided the District mitigates for the "taking" of species by the establishment of habitat for the species in other areas or through other measures. The USFWS issued the District an ITP for operation of Roosevelt Dam in 2003.
The District has reserved funds, that it believes will be sufficient to implement the Plan.
The District engaged in similar consultations with the USFWS to obtain an ITP for operation of Horseshoe and Bartlett Dams on the Verde River. On April 21, 2005, the USFWS granted a permit, known alternately as a "research and recovery permit" or an "enhancement of survival permit," pursuant to the ESA. While there is indication the permit could be challenged, the risk of a "take" of any species will diminish to near zero by early June 2005 as the reservoir is lowered.
The USFWS has proposed a rule to designate "critical habitat" for one of the species affected by SRP reservoir operations, the Southwestern Willow Flycatcher. To the extent the final designation encompasses lands in or near the SRP reservoirs, the USFWS could reopen consultation on the Roosevelt ITP or the Verde River ITP.
Indemnifications - From time to time the District enters into agreements that provide indemnifications relating to liabilities arising from or related to those agreements. Generally, a maximum obligation is not explicitly stated in the indemnifications and, therefore, the overall maximum amount of the obligations under such indemnifications cannot be reasonably estimated. Based on historical experience and evaluation of the specific indemnities, the District does not believe that any material loss related to such indemnifications is likely and, therefore, no related liability has been recorded.
Air Quality - The federal Clean Air Act as amended, among other things, requires reductions in sulfur dioxide and nitrogen oxide emissions from electric generating stations and regulates emissions of hazardous air pollutants by generating stations.
In December 1999, the participants in Mohave Generating Station settled a lawsuit alleging numerous and continuing violations of opacity and sulfur dioxide standards. Under the terms of the settlement, the participants must install by January 1, 2006, a sulfur dioxide scrubber and other pollution control equipment. Major plant modifications, including emissions controls, are required for continued operation as a coal-fired plant. Capital costs are estimated at $710.4 million, of which the District's share would be $142.1 million. These costs are included in capital contingencies portion of the 2005-2010 Improvement Program. However, as discussed in Note (10) Regulatory Issues, the uncertainty in post-2005 coal and water supply have caused the Mohave Participants to be unwilling to make the necessary investments at this time.
SRP 2005 ANNUAL REPORT 49
NOTES TO COMBINED FINANCIAL STATEMENTS April 30, 2005 and 2004 Congress is considering new legislation, including amendments to the Clean Air Act (CAA), which could affect the cost of generating and purchasing power. While it is too early to determine whether the legislation will be enacted, and in what form, or what their effect will be, the changes may materially impact the cost of power generated at affected generating units. Most recently, in March 2005, the Senate Environment and Public Works Committee held hearings on the Clear Skies Act, a bill that would have achieved substantial reductions of sulfur dioxide, oxides of nitrogen and mercury emissions in a coordinated and phased manner. The bill would have provided the electric power generating industry with regulatory certainty while maintaining fuel supply diversity. The bill was not reported out of Committee and the prospect for new CAA legislation in 2005 is low. The District is planning on future emission reductions at its coal-fired power plants as a result of legislative and regulatory initiatives.
The EPA issued final regulations for the control of mercury emissions from coal-fired utility boilers on May 18, 2005. The District is evaluating the impact of the final regulations, which could require the installation of new emission controls at some of its coal-fired power plants. Eleven states have filed a lawsuit challenging the EPA mercury rule claiming it is not protective enough of public health and contrary to the CAA. The District is monitoring developments associated with the lawsuit and its implications on the control requirements. The specific level of reduction and compliance cost will not be known until new legislation is passed, or the EPA and the states finalize regulatory programs under the CAA.
The District is also closely monitoring global warming policy developments at both a federal and regional level. Federal legislation has been proposed which would cap emissions of carbon dioxide from fossil fuel power plants. There have also been several regional initiatives aimed at curbing utility carbon dioxide emission levels. The District is assessing the risk of these policy initiatives on its generation assets and is developing contingency plans to comply with any future laws and regulations restricting carbon dioxide emissions.
Coal Mine Reclamation - In management's opinion, there are sufficient accruals in the accompanying combined financial statements for the District's obligation to reimburse certain coal providers for amounts due for certain coal reclamation costs. However, the District is contesting certain other coal mine reclamation costs. Neither the District's responsibility nor the ultimate amount of liability, if any, can be determined at this time. Management does not believe that the outcome of these matters will have a material adverse effect on the District's financial position or results of operations.
Gas Supply - Effective September 1, 2003, FERC converted the full requirement contracts of the District and other entities in Arizona with El Paso Natural Gas Company for the transportation of natural gas to contract demand status with monthly limits for natural gas transportation service. The District has prepared a gas transportation plan that should provide the District with sufficient gas to meet its retail electric demands. As part of the gas transportation plan, the District is considering alternatives, including gas storage and taking gas transportation service from firms that have proposed new pipelines into or through Arizona, in order to mitigate the impact of an adverse outcome. This plan would, therefore, provide alternatives to the current environment where there is a single provider of gas transportation service to the District.
Proposition 200 - In November 2004, Arizona voters approved Proposition 200, Arizona Taxpayer and Citizen Protection Act, which requires state and local government employees to verify the immigration status of people applying for "public benefits" and to report violators to immigration authorities. There are challenges to Proposition 200 in both the Federal District Court and the Maricopa County Superior Court. As a non-tax supported agricultural improvement district, the District does not believe that it is subject to the law. However, if the law were found to apply to the District, District employees could be required to verify immigration status of electric customers prior to providing service.
Voluntary Contributions in Lieu of Taxes - The Arizona Department of Revenue (ADOR) challenged the District's exclusion of contributions in aid of construction (CIAC) in calculating the total value of District property for purposes of computing voluntary contributions in lieu of taxes ("in lieu contributions") paid by the District. While the District obtained a favorable ruling from the Arizona State Board of Equalization, the Arizona Tax Court subsequently rendered a favorable decision to the ADOR on appeal.
The District appealed the decision of the Arizona Tax Court. If the District does not prevail on appeal, it would be liable for approximately $13.8 million plus interest for fiscal years 2003 (4 months), 2004, and 2005 (8 months). The District believes it has adequate reserves for this potential liability. For calendar years 2005 and forward, legislation has been passed that removes 50 ISRP 2005 ANNUAL REPORT
NOTES TO COMBINED FINANCIAL STATEMENTS April 30, 2005 and 2004 the value of CIAC from the in lieu contribution formula. The legislation codifies the exclusion of CIAC from computing in lieu contributions that could have had approximately $7.3 million per year effect for the District.
The Arizona Legislature also passed legislation that reduces the assessment ratio for calculation of in lieu contributions in Arizona beginning in calendar year 2006. The current rate of 25% will be reduced to 20% over a 10-year period. Because the tax year is based on a calendar year, the first reduction for in lieu contributions will include only four months of the District's fiscal year 2006.
The estimated reduction for fiscal year 2006 is $.52 million. The reduction for fiscal year 2007, the first full fiscal year for the District, is estimated to be $2.2 million. The reduction will continue to accumulate through fiscal year 2016, when the assessment ratio reaches 20%.
California Energy Market Issues - A number of lawsuits have been filed concerning aspects of the California energy market. In addition, the State of California and federal authorities are conducting investigations and other proceedings concerning various aspects of the energy market. Several of the proceedings involve potential refundsl Several of these investigations focus on the involvement of Enron in allegedly manipulating the market.
Because the District bought and sold power into the California energy market, the District has been drawn into many of the proceedings. However, the District was a net buyer in the California market during the time periods being scrutinized, and believes it is entitled to refunds if any are ordered and, in fact, has received approximately $7.7 million in refunds to date.
Indian Matters - From time to time, SRP is involved in litigation and disputes with various Indian tribes on issues concerning regulatory jurisdiction, royalty payments, taxes and water rights, among others (see Navajo Nation Lawsuit and Air Quality above). Resolution of these matters may result in increased operating expenses.
Water Rights - The District and the Association are parties to a state water rights adjudication proceeding encompassing the entire Gila River System (the "Gila River Adjudication"). This proceeding is pending in the Superior Court for the State of Arizona, Maricopa County, and will eventually result in the determination of all conflicting rights to water from the Gila River and its tributaries, including the Salt and Verde Rivers. The District and the Association are unable to predict the ultimate outcome of this proceeding.
The United States, on behalf of the Gila River Indian Community ("GRI Community"), filed a lawsuit in 1982 in the Federal District Court, District of Arizona, to protect the water right claims of the GRI Community. The Association is among the many defendants named in this lawsuit. The lawsuit claims that the defendants' use of surface water and groundwater violates the GRI Community's rights to water in certain specified areas, and requests a decree specifying the GRI Community's rights, injunctive relief to stop the alleged illegal use of water by the defendants, and damages for increased costs to the GRI Community from, among other things, having to deepen its wells. This lawsuit has been stayed pending the outcome of the Gila River Adjudication.
Recently, the U.S. Congress enacted the Arizona Water Rights Settlement Act of 2004, which, when fully implemented, will resolve the claims of the GRI Community listed above as well as many of the claims in the Gila River Adjudication. However, there are many conditions precedent to the full effectiveness and enforceability of the act and its associated agreements.
In 1978, a water rights adjudication was initiated in the Apache County Superior Court with regard to the Little Colorado River System. The District has filed its claim to water rights in this proceeding, which includes a claim for groundwater being used in the operation of CGS. The District is unable to predict the ultimate outcome of this proceeding, but believes an adequate water supply for CGS will remain available.
Other Utigation - In the normal course of business, SRP is exposed to various litigations or is a defendant in various litigation matters.
In managements opinion, the ultimate resolution of these matters will not have a material adverse effect on SRP's financial position or results of operations.
Self-Insurance - The District maintains various self-insurance retentions for certain casualty and property exposures. In addition, the District has insurance coverage for amounts in excess of its self-insurance retention levels. The District provides reserves based on management's best estimate of claims, including incurred but not reported claims. In managements opinion, the reserves established for these claims are adequate and any changes will not have a material adverse effect on the District's financial position or results of operations.
SRP 2005 ANNUAL REPORT 151
REPORT OF INDEPENDENT AUDITORS To the Board of Directors of Salt River Project Agricultural Improvement and Power District, and the Board of Governors of Salt River Valley Water Users' Association In our opinion, the accompanying combined balance sheets and the related combined statements of net revenues and comprehensive income (loss) and of cash flows present fairly, in all material respects, the financial position of Salt River Project Agricultural Improvement and Power District and its subsidiaries and Salt River Valley Water Users' Association (collectively, the Company) at April 30, 2005 and 2004, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide.a reasonable basis for our opinion.
As discussed in Note 2 to the combined financial statements, the Company changed the manner in which it accounts for asset retirement costs as of May 1, 2003.
PricewaterhouseCoopers, LLP Los Angeles, California June 7, 2005 52 ISRP 2005 ANNUAL REPORT
SRP Boards and Councils SRP Boards The two Boards of Salt River Project work with managem-ent to establish policies to further the business affairs of SRP.
The Salt River Valley Water Users' Association (the "Association") is SRFs private water corporation, which administers the water rights of SRP's 248,239-acre area, and operates and maintains the irrigation and drainage system. The 10 members of the Association Board of Governors serve staggered four-year terms and are elected from voting districts by the landowners within the water service territory.
The Salt River Project Agricultural Improvement and Power District (the "District") is SRP's public power utility and-a political subdivision of Arizona. The 14 members of the District Board of Directors serve staggered four-year terms. Ten District Board members are elected from voting divisions and four are elected! at-large'by landowners within the District's boundaries. Most often, candidates seek election'to both Boards.
SRP Councils The two Councils of Salt River Project enact and amend bylaws relating to business affairs of SRP and also serve as liaisons to District electors and Association shareholders.
As with the SRP Boards, there is one Council for the Association and one for the District.
The 30 Association Council members are elected to staggered four-year terms from 10 districts. The 30 District Council members are elected to staggered four-year terms from 10 divisions. Most. often, candidates seek election to both Councils.
The 10 voting areas for SRP Boards and Councils are indicated in blue; total area equals 375 square miles.
SRP 2005 ANNUAL REPORT 153
SRP Boards
/N
'N 6':
Clarence C.
Gilbert R. Rogers Jack M. White Jr.
Pendergast Jr.
District/Division 4 Disht;ct/Division 6 Larry D. Rovey District/Division 2 Elvin E. Fleming Carl E. Weiler District/Division 1 District/Division 3 District/Division 5 Keith B. Woods District/Division 7 SRP Councils
'I, left to right A John R. Starr Kevin J. Johnson Robert L. Cook District/Division 1 left to right V Ann M. Burton Mark A. Lewis Harmen Tjaarda Jr.
District/Division 7 left to right Wayne A. Weiler 0-Stephen H. Williams Ramon P. Trujillo District/Division 5 left to right A John A. Vanderwey Paul E. Rovey Wayne A. Hart Vice Chairman District/Division 2 left to right Deborah S. Hendrickson
- John R. Hoopes Choirmon Mark L. Farmer District/Division 8 54 ISRP 2005 ANNUAL REPORT
Robert G. Kempton Dwayne E. Dobson William W. Arnett Wendy Marshall Hancock District/Division 8 District/Division 10 Director-at-large, seat 12 Director-at-large, seat 14 Dale C. Riggins Jr.
David Rousseau Fred J. Ash District/Divisior 9 Director-at-large, seat 1 1 Director-at-large, seat 13 left to right 4 Robert T. Van Hofwegen Mario J. Herrera John E. Anderson District/Division 3 left to right Robert W. Warren Io Ben A. Butler Jacqueline L. Diller Miller District/Division 6 left to right A Lloyd E. Banning Charles D. Coppinger Leslie C. Williams District/Division 4 left to right V William P. Schrader Jr.
Mark V. Pace Orland R. Hatch District/Division 10 left to right 4 W. Curtis Dana Arthur L. Freeman Edward E. Johnson District/Division 9 SRP 2005 ANNUAL REPORT 155
Two-Year Financial and C Financial Data ($000)
Total operating revenues Electric revenues Water & irrigation revenues Total operating' expenses Total other income, net Net financing costs Net revenues for the year Taxes and tax equivalents Utility plant, gross Lonq-termdebt, net of current portion
)perational Review 2005
$2,251,723 2,238,937 12,786 1,815,538 31,902 105,637 362,450 105,475 9,043,377 2,727,348 2004
$2,077,314 2,065,496 11,818 1,867,397 28,615 115,605 112,220 100,693 8,726,559 2,912,849 Electric revenue contributions to support water operations
.56,672 62,925 Selected Data Debt service coverage ratio 2.39 2.00 Total electric sales (million kWh) 35,516 33,806 Peak-SRP retail customers (kW) 5,665,000 5,673,000 Water deliveries,(acre-feet)*
890,424 Runoff (acre-feet)*
702,974 Employees at year-end 4,336 4,267 Electric customers at year-end 858,314 824,416
- Water data is by calendar year, all other data is by fiscal year ending April 30.
Corporate Officers President Vice President Secretary Treasurer Executive Management General Manager Associate General Managers Corporate Counsel Manager William P. Schrader John M. Williams Jr.
Terrill A. Lonon Steven J. Hulet Richard H. Silverman David G. Areghini, Power, Construction & Engineering Services Mark B. Bonsall, Commercial & Customer Services D. Michael Rappoport, Public & Communications Services John F. Sullivan, Water Group L.J. U'Ren, Operations, Information & Human Resources Services Jane D. Alfano Richard M. Hayslip, Environmental, Land, Risk Management
& Telecom 56 ISRP 2005 ANNUAL REPORT