a costly and sometimes problematical interconnec-

Pacific Gas

control

to cer-

that it has

ces and

power

and that

its re-

usage con-

at the

house, a

plants

canal system, and at three district-owned natural

resources are supplemented through contracts

and geothermal sources, as well as short-term pur-

The Walnut Energy Center was erected

r

trial

ser

2005

ing 8

year,

unpr

grown

grew

fourth quarter of 2004 and the present day.

power plant technicians and others required

Walnut Energy Center. The District also had

Message from the General Manager

As this annual report reveals, 2005 was an especially meaningful year for

the Turlock Irrigation District for several significant reasons, not the least of

which was its certification and commencement of operations as an indepen­

dent control area within the nation’s Western power grid.

On December 1, 2005, the District assumed full responibility for gen­

erating, securing, scheduling and delivering all of its customers’ electrical

energy. Previously, the California Independent System Operator provided

scheduling services under

tion agreement with the

& Electric Co.

To achieve independent

area status, the District had

tify among other things

adequate generation resour

reserves to supply the total

demand of its customers

it has the ability to balance

sources with customer

tinuously. This is accomplished

with electricity generated

Don Pedro Dam & Power

string of small hydroelectric

on its extensive irrigation

gas-fired power plants. These

with hydroelectric, coal

chases from other wholesale suppliers.

Independent control area operations will save the District a substantial

amount of money over the years by eliminating certain charges that had been

imposed directly or indirectly by the statewide system operator for providing

the services the District is now performing for itself. Those charges were in

excess of $2 million per year and were subject to unpredictable increases.

Construction of TID’s third and largest natural gas-fired power plant, the

250-megawatt Walnut Energy Center, progressed steadily throughout 2005.

The project culminated in late February 2006 when the $200 million three­

unit combined-cycle, combustion and condensing turbine generating plant

commenced commercial operations. The new plant virtually doubled the

amount of power the District was capable of generating for itself and further

cemented its self-sufficiency.

to accommodate the steady

esidential, commercial and indus­

growth occurring within the

District’s 662-square-mile electric

vice area. Impressive figures for

showed energy sales increas­

percent over the preceding

while the number of electric

accounts swelled by approximately

4,000 to more than 95,000.

In order to keep up with this

ecedented growth, TID has

organizationally as well. The

number of allocated staff positions

from 418 to 464 between the

Many of the jobs went to new

to maintain and operate the

to train and certify power con­

trol center operators as required by the North American Electric Reliability

Council. In other areas, the District was successful in drawing highly quali­

fied employees from within its service area to fill job vacancies created to

better serve our customers.

In April, the District resolved its long-standing dispute with the San

Francisco Public Utilities Commission (SFPUC) over the latter’s attempt to

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� ©2006 Ron Niebrugge, Photographer

Steadfast and Sure

terminate a contract requiring it to deliver firm power to TID. In 2001, the

SFPUC moved to cancel a 1987 agreement that provided TID with low-cost

power year-round, even during months when San Francisco’s Hetch Hetchy

hydroelectric dams were not producing.

A settlement agreement reduced the financial risks for the SFPUC – which

took substantial losses during the 2001-2002 California energy crisis – while

continuing to provide TID with low-cost Hetch Hetchy system hydropower

for its agricultural pumping and municipal power needs as required under

a 1913 act of Congress. The SFPUC also agreed to continue making excess

Hetch Hetchy hydropower available to TID at attractive pricing. With the is­

sue resolved, the parties have been able to move forward and resume a stable

and cordial business relationship.

The District also resolved a question raised by environmentalists over the

use of herbicides to control aquatic weed growth in unlined canals and later­

als. The issue surfaced in February 2004 when environmentalists challenged

the use of chemical herbicides by TID and four other local irrigation districts

to control moss and algae that would choke canals and clog pipelines.

TID was able to show through a focused environmental impact study

that the chemical treatment of 37 miles of its unlined canals posed no prob­

lem to the underlying groundwater, a major question raised by the environ­

mental groups. In May 2006, a Sacramento Superior Court judge accepted

the findings of the environmental impact report and cleared the way for the

District to resume using chemical means to eliminate weeds.

In the intervening months, however, aquatic weed infestations became

particularly troublesome in the unlined canals where removal was limited to

labor intensive mechanical means including rakes that scoop the weeds up to

the side and deposit them on the bank to a large chain that is dragged by two

trucks astride the canal to dislodge weeds clinging to the sides and bottom.

While those measures kept the water flowing, the canals’ capacity was

reduced and weeds knocked loose during the processes were getting caught

on gates and valves, hindering efficient irrigation of fields.

Accumulated precipitation in the Tuolumne River watershed where the

District secures its irrigation water totaled 53 inches, or 148 percent of the

average as of July 2006, thus guaranteeing a full reservoir going into the sum­

mer growing season. A full reservoir not only assures regular water allotments

to irrigators, it also allows the District to maximize hydroelectric generation

at Don Pedro’s hydroelectric project.

While the 2005-2006 water year is one of the more bountiful in TID

history, much of the precipitation arrived well after the usual end of the rainy

season, drenching fields and orchards and generally impeding growers’ abil­

ity to get into their fields to plant. Instead of carrying water for irrigation

purposes, many of TID’s canals and laterals remained in service as they do

much of the winter for urban storm drainage.

In 2005 the District renewed its commitment to adding environmentally

friendly, renewable energy resources and encouraging customers to partici­

pate in energy efficiency programs. As we looked to the future of both the

District and the energy industry, we acknowledge that the continued empha­

sis on efficient and responsible use of all of our resources suits not just our

customers but also our region and our state.

All in all, 2005 was a vibrant year for the Turlock Irrigation District.

Throughout, TID reaffirmed its commitment to its diverse set of customers

to provide efficient, reliable and high quality services at the most competitive

rates possible. In so doing, the District’s contribution to a strong, stable and

growing local economy was immense.

Larry Weis, General Manager

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On Course

As years go, 2005 was momentous for the Turlock Irrigation District as

actions and projects initiated months and even years earlier culminated to

buttress its autonomy and self-sufficiency as an independent retail electric

provider in one of the fastest growing regions of Central California.

The two most significant events that transpired during 2005 were the

approaching commissioning of a new 250-megawatt natural gas-fired power

coxswains carry out the captain’s instructions. They direct the activities of a

team of highly trained crewmembers responsible for everything from main­

taining the vessel and its rigging at peak performance and seeing to the ship’s

stores and the needs of the many passengers.

A league from shore, the captain orders a leeward course correction to

steer clear of a violent squall brewing on the horizon. After several unevent­

plant and becoming an autonomous electric service ful weeks at sea, the ship arrives safely at its destina­

control area within the expansive Western Intercon- The two most tion and the captain deftly maneuvers it up to the pier

nection territory governed by the Western Electricity where the crew makes it fast with spring lines. As the

Coordinating Council. significant events that

passengers disembark and new ones come aboard, the

With one, the District’s portfolio of internal pow­ transpired during 2005 crew commences the routine tasks of making ready for

er production resources would nearly double, while

the other afforded more control over directing its en­were the approaching

another voyage.

This brief scenario is analogous to TID’s emergence

ergy resources. Both held the promise of improved commissioning of a new as a stand-alone, self-reliant public power utility that is

cost controls and further protection for District retail

electric customers from the volatility of an erratic and 250-megawatt natural

for the most part shielded from the capricious dictates

and interference from outside forces that threaten to

unpredictable energy marketplace. gas-fired power plant and undercut its long-standing strategic objectives of main-

In nautical terms, one might say the District becoming an taining strong local control and financial stability by

has attained the status of a “privileged ship” where owning and controlling adequate energy resources to

it no longer must “give way” to other vessels plying autonomous electric service serve the demands of its retail electric customers.

the high seas of the competitive energy market. Like control area. At TID, energy independence has always been an

a sleek three-masted staysail schooner of yesteryear, important strategic objective. And customers continue

TID is fully capable of casting off the life-support lines to reap the benefits of far-sighted policies and decisions

that made it dependent on others and setting sail on an extended passage

unfettered by outside constraints and demands.

As the schooner quietly clears the harbor, the captain shouts the com­

mand to hoist the sails and shapes a flexible course that assures the passen­

gers and crewmembers of a safe and successful voyage. No fewer than seven

that have come to exemplify the collective wisdom and commitment of the

District’s paid and elected leaders.

In achieving independent control area status, TID was able to sever its

operational and financial commitments to the California Independent System

Operator (Cal-ISO), which had provided those services for the District at a

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Full Speed Ahead

©2003 Wojtek (Voytec) Wacowski | VOYTEC.COM

cost of approximately $2 million annually. Operating its own control area

also allowed the District to schedule surplus electric capacity on the power

grid and earn wholesale revenues in markets that had been closed to it while

Cal-ISO provided control area services. Of equal importance, TID is no lon­

ger subject to power curtailment mandates as experienced during the energy

crisis of 2001 and 2002.

out the Western Electricity Coordinating Council’s 1.8 million square-mile

service territory.

The single largest expenditure was $750,000 for a new energy manage­

ment system that generates the required calculations and performance sta­

tistics required by the WECC and the North American Electric Reliability

Council (NERC). In addition, the newly installed program automatically con-

To have its own control area, the District had to trols the output of the District’s generating resources to

prove among other things that it possessed adequate accommodate customers’ energy demand at any given

resources to supply the total power demand of its cus­ moment – a requirement for all certified control areas.

tomers. Today, this is accomplished with power the Created in 1887, TID In the process of seeking certification, the District

District generates for itself at three natural gas-fired became a generator and created a second power control center as a back up to

power plants, its hydroelectric facilities at Don Pedro its existing control center located in central Turlock. The

Dam on the Tuolumne River and a string of small hy­ distributor of electricity in backup center is available in the event the District has

dro installations sited on its extensive irrigation canal to abandon the existing center in case of an emergency.

system. Additional energy is secured on the wholesale 1923 and today is among All of the District’s 12 power control center operators

market from outside providers under short- and long­ the fifty largest Public achieved NERC certification necessary to accommodate

term contracts. the demands required of Control Area members.

Created in 1887, TID became a generator and Power Electric systems in For the time being, the District is providing control

distributor of electricity in 1923 and today is among area services only within its existing electric service area

the fifty largest Public Power Electric systems in the the nation. but is open to opportunities that may arise in the future

nation. The District provides safe, affordable and reli­ to provide scheduling and other services to additional

able electric service to a customer base that currently utilities.

numbers in excess of 95,000 homes, farms and busi- While control area certification gave the District its

nesses in a 662-square-mile service area encompassing portions of Stanislaus,

Merced and Tuolumne counties.

In gearing up to operate its own control area, the District budgeted $1.4

million to pay for computer upgrades, salaries for additional employees,

training and myriad other things required of Control Area operators through­

autonomy, the new Walnut Energy Center substantially increased its energy

self sufficiency and reduced its growing reliance on outside sources for elec­

tricity to accommodate the energy needs of a swelling service area.

The three-unit combined-cycle, combustion and condensing turbine

generation plant was built at a cost of $200 million to accommodate the rapid

�

residential, commercial and industrial growth occurring inside the District, as

well as replace power being purchased under favorably priced long-term con­

tracts that are beginning to expire. During its initial years of operation, the

plant will produce surplus power that the District can sell on the wholesale

market to help pay for the facility.

It is anticipated that the plant will save the District approximately

$350 million in power purchases from outside suppliers between 2006 and

2025. The exact amount will

depend on several variables, in­

cluding the availability and price

variations of wholesale energy

and natural gas.

The Walnut Energy Center

is rated as among the cleanest

power generating facilities of

comparable size in the nation.

Its air emissions are as much as

85 percent lower than those of

older generating facilities cur­

rently operating in California.

The plant is designed to use

treated effluent (recycled water)

from the City of Turlock’s Wastewater Treatment Plant for cooling and process

water needs.

This

©2006 Jeff Broome Photography

The new plant complements TID’s existing power generating portfolio

that includes hydroelectric facilities producing 154 megawatts at Don Pedro

Dam on the Tuolumne River and a string of small scale hydroelectric plants

on the District’s extensive irrigation canal system, as wll as two existing 49-

megawatt natural gas–fired plants – a base load plant and a peaking facility

– all located within the District’s 662-square-mile electric service area.

The District is continually on the lookout for other energy opportuni­

ties. Among other things, it has an interest in a geothermal power plant in

Lake County and an entitlement to power generated at a coal-fired plant in

southeastern Oregon. In 2005, the District acquired an interest in a produc­

ing natural gas field in Wyoming. The Pinedale purchase is expected to pro­

vide the District between 1,200 to

4,600 MMBtu/day over 25 years.

represents on average 17

percent of the District’s estimated

natural gas needs to serve retail

electric load and 9 percent of the

Walnut Energy Center’s estimated

total natural gas needs within the

next 20 years. Based on current

information and market condi­

tions, the Pinedale purchase could

save the District $18 million on a

net present value basis.

By carefully managing its own

resources and balancing them

with other existing and prospective new resources, the District is confident

it can continue to meet its customers’ growing energy demands for many

years to come.

Photo: Walnut Energy Center

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General Manager

Robert Nees

Assistant General Manager

Assistant General Manager

Energy Resources

Casey Hashimoto

Assistant General Manager

Engineering & Operations

Martin Purdy

Assistant General Manager

Human Resources

Randy Baysinger

Assistant General Manager

Power Generation

Joe Malaski

Assistant General Manager

Financial Services

Steve Boyd

Assistant General Manager

Consumer Services & Government Relations

Management Team

Larry Weis

Water Resources & Regulatory Affairs

Ken Weisel

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Historical Operating Statistics

2005 2004 2003 2002 2001 Average Customers At End Of Period:

(1)

Residential 68,257 65,218 62,813 56,480 55,505 Commercial 6,584 6,419 6,094 5,508 5,416 Industrial 730 687 718 613 592 Other (2) 18,346 17,307 15,646 14,944 11,888(4)

Total 93,917 89,631 85,271(5) 77,545 73,401 MWh SALES: (1)

Residential 678,878 661,266 602,930 551,132 544,930 Commercial 121,825 119,746 109,644 98,991 99,240 Industrial 675,016 651,200 584,283 544,995 522,229 Other (2) 338,395 327,811 306,511 298,345 284,873 Total Retail 1,814,114 1,760,023 1,603,368 1,493,463 1,451,272

Wholesale Power 988,572 550,396 557,965 553,520 1,002,446 Total 2,802,686 2,310,419 2,161,333 2,046,983 2,453,718

Sources Of MWh: Generated by district 776,112 425,110 337,430 419,211 643,359 Purchased 2,148,639 2,027,574 1,915,356 1,744,398 1,875,316 Subtotal 2,924,751 2,452,684 2,252,786 2,163,609 2,518,675

System losses 122,065 142,265 91,453 116,626 64,957 Total 2,802,686 2,310,419 2,161,333 2,046,983 2,453,718

Electric Energy Revenues: (1)

(In Thousands) Residential $70,659 $65,231 $58,563 $48,547 $47,680 Commercial 11,630 11,081 9,988 8,909 8,979 Industrial 44,643 40,100 35,336 30,744 29,773 Other (2) 26,535 24,152 22,561 21,303 20,447 Total Retail Energy 153,467 140,564 126,448 109,503 106,879

Electric Service Charges 284 295 213 127 74 Other Electric Revenue 164 (645) 94 118 170

Electric Energy Retail 153,915 140,214 126,755 109,748 107,123 Wholesale Power 58,296(6) 24,081(6) 22,335(6) 21,232 201,108 Total $212,211 $164,295 $149,090 $130,980 $308,231

System Peak Demand (MW) 476 437 406 397 410 Average MWh Sales Per Customer For The Period

Residential 9.946 10.139 9.599 9.758 9.818 Commercial 18.503 18.655 17.992 17.972 18.323 Industrial 924.679 947.889 813.765 889.062 882.144

Average Revenue Per MWh For The Period

Residential $104.08 $98.65 $97.13 $88.09 $87.50 Commercial $95.46 $92.54 $91.09 $90.00 $90.48 Industrial $66.14 $61.58 $60.48 $56.41 $57.01

Average Cost Of Power Per Kwh For Retail Load(4) $0.046 $0.054 $0.048 $0.055 $0.047

(1) Prior years have been reclassified to con­form with current year presentation.

(2) Includes agricultural and municipal water pumping, street lighting, and interdepartmental meters.

(3) Includes depreciation, excludes debt ser­vice.

(4) Summary accounts are now counted by individual connections.

(5) District acquired Westside Service territory which included 5,778 accounts.

(6) Includes adjustments for transaction “book­outs” which were not physically settled into the District’s system.

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Historical Results of Operations

(in thousands) 2005 2004 2003 2002 2001 Operating Revenues:

Electric energy - Retail $153,915 $140,214 $126,755 $109,748 $107,123 Electric energy - Wholesale 58,296(2) 24,081(2) 22,335(2) 21,232 201,108 Small Hydropower Other Electric Irrigation 6,105 5,603 5,191 5,392 5,172 Other 4,911 3,449 343(3) 103 16 Total Operating Revenue 223,227 173,347 154,624 136,475 313,419

Operating Expenses: Power Supply: Purchased Power 120,184(2) 103,074(2) 89,108(2) 72,766 215,010 Generation and Fuel 14,164 11,847 8,064 22,174(1) 44,686

Total Power Supply 134,348 114,921 97,172 94,940 259,696 Other Electric O&M 12,593 14,459 10,823 10,301(1) 10,099 Irrigation O&M 8,302 8,032 8,490 8,369 7,159 Public Benefits 3,133 2,855 2,102 1,677(1)

Administration and General 14,915 15,208 14,191 12,469 11,820 Depreciation and amortization 15,936 14,360 13,121 12,316 12,252 Total Operating Expenses 189,227 169,835 145,899 140,072 301,026

Operating Income (Loss) 34,000 3,512 8,725 (3,597) 12,393

Other Income (Expense): Interest 3,409 2,901 5,292(3) 7,423 10,164 Unrealized (Loss) Gain on Investments Miscellaneous 6,571 5,955 6,117(3) 4,094 3,506 Total Other Income 9,980 8,856 11,409 11,517 13,670

Interest Expense Long Term Debt 10,902 9,194 9,920 10,644 11,642 NCPA Obligation

Transfer (To) From Deferred Regulatory Credits 0 0 0(3) (1,220) (5,820)

Net Income (Loss) 33,078 3,174 10,214 (3,944) 8,601

Retained Earnings: Beginning of Year 272,225 269.051 258,837 262,781 254,180

(1) Revised 2002 to reflect Public Benefits End of Year $305,303 $272,225 $269,051 $258,837 $262,781 (2) Includes adjustments for transaction “book-

Debt Service Coverage ­ Revenue Bonds/COP’s 2.71x 1.64x(4) 1.83x 1.36x 1.31x

outs” which were not physically settled into the District’s system.

(3) Revised 2004 to reflect changes in reporting format.

(4) Rate Stabilization transfer of $7,240.

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Report of Independent Auditors

To the Board of Directors of

Turlock Irrigation District

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of revenues, expenses and changes in net assets and of cash flows present fairly, in all material aspects, the financial position of Turlock Irrigation District and its blended component unit (the “District”) at December 31, 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 District’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 opinions.

The management’s discussion and analysis included on pages 13 through 16 is not a re­quired part of the basic financial statements but is supplementary information required by the Governmental Accounting Standards Board. We have applied certain limited proce­dures, 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.

May 19, 2006

Management’s Discussion & AnalysisThe following management’s discussion and analysis of the Turlock Irrigation District (the “District”) and its financial performance provides an overview of the District’s financial ac­tivities for the years ended December 31, 2005 and 2004. This management’s discussion and analysis should be read in conjunction with the District’s financial statements and ac­companying notes, which follow this section.

Background The District is an irrigation district organized under the provisions of the Irrigation District Act and has the powers provided therein. Organized in 1887, the District was the first of 65 irrigation districts to be formed in the State of California. The Board of Directors (the “Board”) governs the District. The five members of the Board are elected from geographic divisions of the District for staggered four-year terms. The Board appoints a general manager and certain other senior managers who are responsible for the operations of the District.

Since 1923, the District has provided all the electric service within its 425 square-mile service area, which includes portions of Stanislaus, Merced and Tuolumne counties. The District’s service area includes the cities of Turlock, Ceres, Hughson and a part of Modesto and the unincorporated communities of Keyes, Denair, Hickman, Delhi and Hilmar.

In December 2003, the District and completed the acquisition of PG&E’s electric distri­bution facilities in a portion of the west side of Stanislaus County, including the City of Patterson, the community of Crows Landing and certain adjacent rural areas (collectively, the “Westside”). The Westside covers approximately 237 square miles and includes 7,713 electric customer accounts.

To provide electric service within its service area, the District owns and operates an electric system, which includes generation, transmission and distribution facilities. Its generating facilities include hydroelectric units and oil and gas-fired facilities. The District also pur­chases power and transmission service from other sources and participates in other utility arrangements.

The District also supplies water for irrigation use within 308 square miles of its service area, comprising approximately 5,800 parcels of land and 250 miles of gravity flow canals and laterals. The District’s electric and irrigation systems are operated and accounted for as a single entity, hence, revenues from both systems are available to pay the obligations of the District.

Rates and Charges The District’s Board has full and independent authority to establish revenue levels and rate schedules for all electric service provided by the District. The District is not subject to retail rate regulation by any State or federal regulatory body, and is empowered to set retail rates effective at any time. The District has maintained rates for electric service that have been sufficient to provide for all operating and maintenance costs and expenses, debt service, repairs, replacements and renewals and to provide for base capital additions to the system. The Board fixes rates and charges of the District based on a cost of service methodology.

The District increased electric rates by an average of 5.00% effective February 1, 2005.

The District has a credit requirement for all new service connections, which requires new customers to verify their good credit standing with their former electric utility provider or to place a deposit with the District if an acceptable credit standing cannot be verified.

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Financial Reporting The District maintains its accounts in accordance with generally accepted accounting prin­ciples for proprietary funds as prescribed by the Governmental Accounting Standards Board (GASB), and where not in conflict with GASB pronouncements, accounting principles pre­scribed by the Financial Accounting Standards Board (FASB). The District’s accounting records generally follow the Uniform System of accounts for public utilities and licensees prescribed by the Federal Energy Regulatory Commission (FERC), except as it relates to the accounting for contributed property.

In accordance with Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation, the Board has taken various regulatory actions for ratemaking purposes that result in the deferral of revenue or expense recognition. At December 31, 2005 and 2004, the District had a regulatory asset of $1.9 million and $2.9 million, respectively, in connection with costs incurred in the District’s acquisition of the Westside facilities from PG&E. At December 31, 2005 and 2004, the District had total regulatory credits of $24.7 million and $23.6 million, respectively, consisting primarily of electric rate stabilization of $21.1 and $21.1 million for 2005 and 2004, respectively. The regulatory assets and credits will be recognized in the statement of revenues, expenses and changes in net assets when determined by the Board for ratemaking purposes.

Investment Policies and Procedures The Board reviews the investment policy on an annual basis. The District also has an Invest­ment Committee, comprised of the Treasurer, Deputy Treasurer, General Manager and two members of the Board. This committee meets on an as-needed basis to review issues related to the District’s investments. The District has contracted with Public Financial Management, Inc. (PFM), a leading investment manager of public entity funds, to invest its cash. PFM only purchases investments on behalf of the District which are permitted by the District’s investment policy. The Bank of New York Western Trust Company holds these investments in custody.

Debt Management Program The District regularly reviews its debt structure, which includes the issuance of refunding bonds to achieve debt service savings. From 1986 through 2003, the District has undergone six refundings comprising a major portion of its debt to achieve debt service savings. In July 2003, the District refunded $35.2 million of its debt to achieve debt service savings of $11.1 million.

Using This Financial Report This annual financial report consists of management’s discussion and analysis and the finan­cial statements, including notes to the financial statements. The annual financial report re­flects the activities of the District primarily funded through the sale of energy, transmission, and distribution services to its retail and wholesale customers, as well as irrigation services.

Component Unit The Walnut Energy Center Authority (the “Authority”) was formed in 2004 for the purposes of developing and operating a 250 MW natural gas fueled generation facility located in the District’s service territory. Although the Authority is a separate legal entity from the District, it is blended into and reported as part of the District because of the extent of its operational and financial relationship with the District. Accordingly, all operations of the Authority are consolidated into the District’s financial statements.

Consolidated Balance Sheets, Consolidated Statements of Revenues, Expenses and Changes in Net Assets, and Consolidated Statements of Cash Flows The consolidated balance sheets include all of the District’s assets and liabilities, using the accrual basis of accounting, as well as information about which assets can be utilized for general purposes, and which assets are restricted as a result of bond covenants and other commitments. The consolidated statements of revenues, expenses, and changes in net assets report all of the revenues and expenses during the time periods indicated. The consolidated statements of cash flows report the cash provided and used by operating activities, as well as cash payments for debt service and capital expenditures and cash proceeds or uses from investment activities.

Summary of Financial Position and Changes in Net Assets (dollars in thousands)

2005 2004 2003 Assets Utility plant, net Cash and investments Other non-current assets Other current assets

$632,441 $510,100 $398,345 170,789 222,920 119,379

8,953 11,754 9,046 45,016 29,479 28,975

$857,199 $774,253 $555,745 Liabilities and Net Assets Long-term debt $412,107 $420,659 $220,339 Other non-current liabilities

and deferred credits 33,230 30,747 33,003 Other current liabilities 106,559 50,622 33,352

Total liabilities 551,896 502,028 286,694 Net assets:

Invested in capital assets, net of related debt 214,875 209,498 222,551 Restricted 9,020 16,043 6,450 Unrestricted 81,408 46,684 40,050 Total net assets 305,303 272,225 269,051

$857,199 $774,253 $555,745

Revenue, Expenses and Changes in Net Assets Operating revenues $223,227 $173,347 $154,624 Operating expenses (189,227) (169,835) (145,899)

Operating income 34,000 3,512 8,725

Investment income 3,409 2,901 5,292 Other income, net 6,571 5,955 6,117 Interest expense (10,902) (9,194) (9,920)

Net increase in net assets 33,078 3,174 10,214

Net assets, beginning of year 272,225 269,051 258,837 Net assets, end of year $305,303 $272,225 $269,051

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Management’s Discussion and Analysis as of and for the Year Ended December 31, 2005 Assets Utility Plant The District has invested approximately $632.4 million in utility plant assets and construc­tion in progress, net of accumulated depreciation at December 31, 2005. Net utility plant makes up 74% of the District’s assets at December 31, 2005, compared to 66% in the prior year. The following chart shows the breakdown of net utility plant by major plant category at December 31, 2005 - generation, transmission,

Natural Gas Other 6% distribution, natural gas supply, unamortized fu- Supply 5%

Generation54%

ture power rights, irrigation and other: Irrigation 6%

During 2005, the District capitalized $138.5 mil- Unamortized Future Power

lion of additions to utility plant, including addi- Rights 2%

tions to construction work in progress. The prima­ry increase was in generation plant and reflects the Distribution

21% costs of approximately $74.4 million for the 250 megawatt (MW), gas-fired Walnut Energy Center Transmission 6% project (the “Project”). The Project achieved com­mercial operation on February 28, 2006 with a total cost of $215.2 million, including capi­talized interest. The District invested $34.6 million in natural gas fields in order to hedge the cost of fuel supply for the project. The District also invested $1.8 million for communi­cation lines and $6.0 million to upgrade certain transmission and distribution assets, $4.8 million for substation construction and $9.7 million for routine expansion which consists of transformers, T&D lines, meters, lights, and new services.

Cash and Investments The District’s cash and investments decreased $52.1 during 2005. This was primarily due to the construction of the Walnut Energy Center.

Other Non-current Assets Other non-current assets decreased $2.8 million. This increase was primarily due to amor­tization of District assets totaling $1.3 million, change in regulatory assets of $.9 million and the collection of a long term receivable totaling $.6 million.

Other Current Assets Other current assets in 2005 increased $15.5 million when compared to 2004. This was primarily due to an increase of wholesale energy receivables of $6.6 million due to an in­crease in wholesale revenues, an increase in re-

Interest Principallated financial derivative instrument, primarily 30000

gas related, of approximately $6.9 million, a $1.5 million increase in prepaid expenses and 25000

a $.4 million increase in accrued interest due to higher interest rates. 20000

Liabilities And Changes In Net Assets 15000

Long-term Debt Long-term debt decreased $8.6 million in 2005. 10000

This was primarily the result of scheduled prin­cipal payments of $8.6 million. 5000

The following table shows the District’s future 0

2006 2007 2008 2009 2010debt service requirements from 2006 through

2010 at December 31, 2005 (dollars in thousands):

At December 31, 2005, the District’s bond ratings are A1 from Moody’s, A+ from Fitch and A+ from Standard and Poor’s.

Other Non-current Liabilities and Deferred Credits Other non-current liabilities and deferred credits increased $2.5 million in 2005. The increase was primarily due to the District recording a long-term financial derivative invest­ment of $1.1 million primarily relating to the value of an electric related contract entered into in September 2005, a $1.1 million increase in public benefits deferred credit and an increase in the District’s share of the Transmission Agency of Northern California obliga­tion of $.3 million.

Other Current Liabilities Other current liabilities increased $55.9 million in 2005. This was primarily the result of the District issuing taxable commercial paper of $32.8 million for investment in gas fields and tax exempt commercial paper of $20.0 million for completion of the Project and an increase in related financial derivative instruments, both gas related and electricity related, of approximately $3.2 million

Changes In Net Assets Operating Revenues Operating revenues increased $49.8 million from $173.3 million in 2004 to $223.2 mil­lion in 2005. Wholesale revenues increased $34.2 million from $24.0 million in 2004 to $58.2 million in 2005 as a result of an approximate 80.6% increase in volumes sold, an increase in the average sales price of approximately 9.1% from an average of approximately $67/MWh in 2004 to$73/MWh in 2005. Retail power revenues were up $13.7 million due to a 5.0% rate increase and a 3% increase in consumption as a result of customer growth from 89,631 in 2004 to 93,917 in 2005. The District had wholesale gas revenues of approximately $3.5 million in 2005 as a result of their investment in a natural gas field compared to $0 wholesale gas revenues in 2004.

Operating Expenses Purchased power, generation and fuel expenses were $134.3 million in 2005 compared to $114.9 million in 2004. Purchased power costs increased by approximately 18.3% due to higher prices during 2005 and higher volumes of power purchases required as a result of increased retail consumption (see operating revenues above). The District’s generation in­creased approximately 82.6% from 425,111 MWh in 2004 to 776,112 MWh in 2005 due to improved hydro conditions and the relatively high price for power relative to the price of gas, which made it more economical for the District to generate with its thermal plants, rather than purchase from the electric market, during certain periods. The District’s other operating expenses remained relatively unchanged.

Investment Income Investment income in 2005 was $.5 million higher than in 2004, primarily as a result of higher interest rates in 2005.

Other Income Other income is up $.6 million in 2005 when compared to 2004. This increase is the result of $.6 million increase in contribution in aid of construction.

Interest Expense Interest expense in 2005 was $1.7 million higher than in 2004, primarily due to higher variable interest rates and the addition of $52.6 million in commercial paper.

��

Management’s Discussion and Analysis as of and for the Year Ended December 31, 2004 Assets Utility Plant The District has invested approximately $510.1 million in utility plant assets and construc­tion work in progress, net of accumulated depreciation at December 31 2004. Net utility plant makes up 66% of the District’s assets at December 31, 2004, compared to 72% in the prior year. The following chart shows the breakdown of net utility plant by major plant category at December 31, 2004 - generation, transmission, distribution, unamortized future power rights, irrigation and other: Other 8%

During 2004, the District capitalized $126.7 Irrigation

Generation52%

7% million of additions to utility plant, including Unamortized

Future Power additions to construction work in progress. The Rights 3%primary increase was in generation plant and reflects the costs of approximately $96.2 million Distribution for the 250 megawatt (MW), gas-fired Walnut 23%

Energy Center project (the “Project”). The District also invested $1.0 million for communi- Transmission 7%

cation lines and $9.9 million to upgrade certain transmission and distribution assets, $3.6 million for substation construction and $5.7 million for construction of a 115 kilovolt transmission line.

Cash and Investments The District’s cash and investments increased $103.5 million during 2004. This was due primarily to the 2004 revenue bond financing of $201.1 million for the Project.

Other Non-current Assets Other non-current assets increased $2.7 million. This was primarily due to the issue costs related to the 2004 revenue bond financing of $3.7 million. Amortization of District as­sets, Westside deferred regulatory asset and refunding losses totaled $1.1 million.

Other Current Assets Other current assets in 2004 remained generally consistent with 2003.

Liabilities And Changes In Net Assets Long-term Debt Long-term debt increased $200.3 million in 2004. This was the result of the $201.1 Interest Principal

30000million revenue bond financing. The District recorded a $7.2 million premium related to

25000 the 2004 financing. There were scheduled principal payments of $8.1 million.

20000

The following table shows the District’s future debt service requirements from 2005 through 15000

2009 at December 31, 2004 (dollars in thou­sands): 10000

At December 31, 2004, the District’s bond rat­5000

ings are A1 from Moody’s, A+ from Fitch and A+ from Standard and Poor’s. 0

2005 2006 2007 2008 2009

Other Non-current Liabilities and Deferred Credits Other non-current liabilities and deferred credits decreased $2.3 million in 2004. The District’s share of the Transmission Agency of Northern California obligation decreased $0.9 million in 2004. There was a $1.2 million decrease due to the FAS 133 valuation regarding forward energy/gas contracts at December 31, 2004, and $0.2 million in other minor changes.

Other Current Liabilities Other current liabilities increased $17.3 million in 2004. Purchase Power Accounts Pay­able increased $1.0 million over 2003. Accounts payable and accrued expenses are up $9.8 million due to general operating expenses and Walnut Energy construction costs. Customer advances are up $1.7 million due to change in deposit policy and customer growth. Accrued Interest Payable is up $4.7 million due to 2004 revenue bond financing. The current portion of derivative financial instruments decreased $0.2 million.

Changes In Net Assets Operating Revenues Operating revenues increased $18.7 million from $154.6 million in 2003 to $173.3 mil­lion in 2004. Wholesale revenues increased $1.8 million from $22.3 million in 2003 to $24.1 million in 2004 as a result of an approximate 1.5% increase in volumes sold, and more importantly, an increase in the average sales price of approximately 7.5% from an average of approximately $54/MWh in 2003 to $58/MWh in 2004. Retail power revenues were up $16.6 due primarily to an 11.6% increase in consumption as a result of customer growth from 85,271 in 2003 to 89,631 in 2004 and the addition of the Westside acquisi­tion in December 2003. Average rates were slightly higher in 2004 since the 2003 rate increase did not impact rates for all of 2003.

Operating Expenses Purchased power, generation and fuel expenses were $114.9 million in 2004 compared to $97.2 million in 2003. Purchased power costs increased by approximately 15.7% due to slightly higher prices during 2004 and higher volumes of power purchases required as a result of increased retail consumption (see Operating Revenues above). The District’s generation increased approximately 26% from 337,430 MWh in 2003 to 425,111 MWh in 2004 due to improved hydro conditions and the relatively high price for power relative to the price for gas, which made it more economical for the District to generate with its thermal plants, rather than purchase from the electric market, during certain periods. The District’s other operating expenses are up $6.1 million due to a $0.8 million increase in public ben­efits expenditures, an increase of $3.6 million in other electric expenses, an increase of $1.2 million in depreciation expenses, a $1.0 million increase in general and administrative expenses, offset by a decrease in irrigation expenses of $0.5 million.

Investment Income Investment income in 2004 was $2.4 million lower than in 2003 as a result of less cash and reserve funds, lower investment yields and a realized gain on the sale of investments of $1.1 million in 2003.

Interest Expense Interest expense in 2004 was $0.7 million lower than in 2003, primarily due to capitaliza­tion of interest related to the Project and other District assets during construction.

Other Income Other income in 2004 was $0.2 million lower than 2003, primarily due to a decrease in property tax revenue.

��

Balance Sheets December 31, 2005 and 2004 (dollars in thousands)

Assets Utility plant, net Investments and other long-term assets:

Long-term investments, including restricted amounts Debt issuance costs and other assets Deferred regulatory asset

Current assets: Cash and cash equivalents, including restricted amounts Short-term investments, including restricted amounts Retail accounts receivable, net Wholesale accounts receivable, net Accrued interest and other receivables Materials and supplies Prepaid expenses and other current assets Derivative financial instruments

Total assets Capitalization and Liabilities Capitalization:

Net assets:Invested in capital assets, net of related debtRestrictedUnrestricted

Total net assetsLong-term debt, net of current portion

Total capitalizationLiabilities and deferred credits:

Deferred regulatory credits Derivative financial intruments, net of current portion Affiliate obligation

Current liabilities:Commercial paper notesCurrent portion of long-term debtPower purchases payableAccounts payable and accrued expensesAccrued salaries, wages and related benefitsCustomer deposits and advancesAccrued interest payableCurrent portion of derivative financial instruments

Commitments and contingencies (Notes 4, 11, 12, and 13) Total net assets and liabilities

The accompanying notes are an integral part of these financial statements.

2005 2004

$632,441 $510,100

76,470 67,210 7,022 8,863 1,931 2,891

85,423 78,964

80,581 106,843 13,738 48,867 11,511 11,223 11,887 5,458

2,413 2,032 2,793 2,676 7,155 5,653 9,257 2,437

139,335 185,189 $857,199 $774,253

$214,875 $209,498 9,020 16,043

81,408 46,684 305,303 272,225 404,747 412,059 710,050 684,284

24,690 23,604 1,138 -7,402 7,143

33,230 30,747

52,569 -7,360 8,600

14,280 11,005 13,485 15,956

5,822 5,589 7,721 7,088 7,867 9,388 4,815 1,596

113,919 59,222

$857,199 $774,253

����

Statements of Revenues, Expenses & Changes in Net Assets

For the years ended December 31, 2005 and 2004 (dollars in thousands)

2005 2004 Operating revenues:

Electric: Retail $153,915 $140,214 Wholesale 58,296 24,081

Irrigation 6,105 5,603 Wholesale Gas 3,519 -Other 1,392 3,449

223,227 173,347

Operating expenses: Purchased power 120,184 103,074 Generation and fuel 14,164 11,847 Other electric 12,593 14,459 Irrigation 8,302 8,032 Public benefits 3,133 2,855 Administration and general 14,915 15,208 Depreciation and amortization 15,936 14,360

189,227 169,835 Operating income 34,000 3,512

Nonoperating revenues and expenses: Investment income 3,409 2,901 Other income, net 6,571 5,955 Interest expense (10,902) (9,194)

(922) (338)

Net increase in net assets 33,078 3,174

Net assets - beginning of year 272,225 269,051 Net assets - end of year $305,303 $272,225

The accompanying notes are an integral part of these financial statements.

��

Statements of Cash Flows For the years ended December 31, 2005 and 2004 (dollars in thousands)

2005 2004 2005 2004 Cash flows from operating activities: Supplemental schedule of cash flows from

Receipts from electric customers $153,168 $143,843 operating activities: Receipts from wholesale power sales 56,611 32,606 Operating income $34,000 $3,512 Receipts from irrigation customers 7,476 9,722 Adjustments to reconcile operating income to Receipts from sales of gas 1,366 - net cash provided by operating activities: Payments to vendors for purchased power Depreciation and amortization 15,936 14,360

and fuel (125,916) (114,857) Derivative financial instruments (2,463) (3,841) Payments to employees and vendors for Other 1,976 1,922

generation and other electric (25,157) (25,981) Changes in operating assets and liabilities: Payments to employees and vendors for irrigation (8,373) (7,929) Accounts receivable (6,952) 2,877 Payments to employees and vendors for Materials and supplies (117) (683)

administration and general (13,803) (13,130) Prepaid expenses and other current assets (1,502) (560) Other receipts, net 671 5,409 Other assets 1,190 494

Net cash provided by operating activities 46,043 29,683 Regulatory assets and credits 2,046 (182) Power purchases payable 3,275 942

Cash flows from capital and related financing activities: Accounts payable and accrued expenses (2,471) 8,967 Acquisition and construction of capital assets (130,979) (120,287) Accrued salaries, wages and related benefits 233 1,166 Proceeds from contributions in aid of construction 4,595 4,033 Customer deposits and advances 633 1,660 Repayment of long-term debt (8,600) (8,135) Affiliate obligation 259 (951) Proceeds from issuance of long-term debt - 204,422 Net cash provided by operating activities $46,043 $29,683 Proceeds from issuance of commercial paper 52,569 -Interest payments on long-term debt (19,022) (9,376)

Net cash (used in) provided by capital and related financing activities (101,437) 70,657

Cash flows from investing activities: Investment income 3,263 3,201 Sales (purchases) of investments, net 25,869 (42,985)

Net cash provided by (used in) investing activities 29,132 (39,784)

Net (decrease) increase in cash and cash equivalents (26,262) 60,556 Cash and cash equivalents, beginning of year 106,843 46,287 Cash and cash equivalents, end of year $80,581 $106,843

The accompanying notes are an integral part of these financial statements.

��

Notes to Consolidated Financial Statements (dollars in thousands)

1. Organization and Description of Business The Turlock Irrigation District (the “District”) was organized under the Wright Act in 1887 and operates under the provisions of the California Water Code as a special district of the State of California. As a public power utility, the District is not subject to regulation or over­sight by the California Public Utilities Commission (CPUC). The District provides electric power and irrigation water to its customers.

The District’s Board of Directors (the “Board”) determines its rates and charges for its com­modities and services. The District levies ad valorem property taxes on property located in the counties of Stanislaus and Merced. The District may also incur indebtedness, including issuing bonds, and is exempt from payment of federal and state income taxes.

2. Summary of Significant Accounting Policies Method of Accounting The District maintains its accounts in accordance with generally accepted accounting prin­ciples for proprietary funds as prescribed by the Governmental Accounting Standards Board (GASB), and where not in conflict with GASB pronouncements, accounting principles pre­scribed by the Financial Accounting Standards Board (FASB). The District’s accounting records generally follow the Uniform System of accounts for public utilities and licensees prescribed by the Federal Energy Regulatory Commission (FERC), except as it relates to the accounting for contributions in aid of construction (CIAC).

Component Unit The Walnut Energy Center Authority (the “Authority”), is a 250 MW natural gas fueled generation facility, which achieved commercial operations on February 28, 2006. Although the Authority is a separate legal entity from the District, it is blended into and reported as part of the District because of the extent of its operational and financial relationship with the District. Accordingly, all operations of the Authority are consolidated into the District’s financial statements.

Use of Estimates The preparation of financial statements in conformity 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 contin­gent 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 Utility plant is recorded at cost. The cost of additions, renewals and betterments are capital­ized; repairs and minor replacements are charged to operating expenses as incurred. Interest and related financing costs are capitalized as a component of major utility plant develop­ment projects. The District capitalized $7,298 and $5,829 of interest during 2005 and 2004, respectively.

Depreciation is computed using the straight-line method over the estimated useful lives, which generally range from 20 to 40 years and 40 to 150 years for electric and irrigation related assets, respectively. The estimated useful lives of furniture, fixtures, equipment and other assets range from 5 to 25 years. Upon retirement, the cost of depreciable utility plant, plus removal costs, less salvage, is charged to accumulated depreciation.

Future power rights are costs incurred by the District in development of hydroelectric fa­cilities owned by others who provide power to the District. Such costs are recorded as a component of utility plant and are being amortized on a straight-line basis over the 49-year periods to which these rights apply.

Investments in Gas Properties In July 2005, the District acquired an approximate 10.6 percent non-operating ownership interest in gas producing properties located near Pinedale, Wyoming for $34.6 million. The District uses the successful efforts method of accounting for its investment in gas producing properties. Costs to drill and equipment development wells are capitalized as a component of property, plant, and equipment on the balance sheet. Costs to drill wells that do not find economically recoverable reserves are expensed. The capitalized costs of producing gas properties, after considering estimated residual salvage values, are depleted by the unit-of-production method based on the estimated future production of proved and probable reserves through the year 2034.

Gas production from the District’s share of these properties is sold to wholesale buyers as an economic hedge to offset the net cost of the District’s gas supply costs. Sales in 2005 totaled $3.5 million.

Cash, Cash Equivalents and Investments Cash equivalents include all debt instruments with original maturity dates of three months or less from the date of purchase and all investments in the Local Agency Investment Fund (LAIF). The debt instruments are reported at amortized cost and the LAIF is reported at the value of its pool shares.

All investments are carried at their fair market value, generally based on market prices quot­ed by dealers for those or similar investments. Investment income includes both realized gains and losses and unrealized changes in the fair market value of investments, unless deferred as a regulatory asset or credit.

In accordance with provisions of the credit agreements relating to the District’s long-term debt obligations, restricted funds held by trustees have been established to provide for cer­tain debt service and project funding requirements. The restricted funds held by trustees are invested primarily in United States (U.S.) government securities and related instruments with maturities no later than the expected date of the use of such funds.

Participation in Joint Power Authorities The District’s ownership investments in joint power authorities (JPAs) represent less than 20% ownership interests, and therefore, are accounted for using the cost method.

Debt Issuance Costs Costs incurred in connection with the issuance of debt obligations, principally underwriters’ and legal fees, are capitalized as debt issuance costs and are amortized, as a component of in­terest expense, over the terms of the related obligations using the effective interest method.

Accounts Receivable and Allowance for Doubtful Accounts Accounts receivable arise from billings to customers for the sale of power and water, and certain improvements made to customers’ properties. Accounts receivable also includes an estimate for unbilled revenues related to power delivered between the last billing and the last day of the reporting period, which amounted to $5,911 and $5,540 at December 31, 2005 and 2004, respectively.

�0

The District recognizes an estimate of uncollectible accounts for its retail and wholesale receivables based upon its historical experience with collections and current market condi­tions. At December 31, 2005 and 2004, the allowance for doubtful accounts relating to retail electric receivables totaled $150 and $574, respectively. At December 31, 2005 and 2004, the allowance on the wholesale receivables of $3,820 relates primarily to collectibility issues resulting from the uncertain California wholesale energy markets. The District re­cords bad debt expense related to electric service and wholesale activities as administration and general in the statements of revenues, expenses and changes in net assets. In 2005 and 2004, bad debt expense relating to uncollectible accounts receivable was $32 and $287, respectively.

Materials and Supplies Materials and supplies are used in the District’s operations and are recorded at average cost.

Long-term Debt Long-term debt is recorded at the principal amounts of the obligations adjusted for original issue discounts and premiums. The premiums and discounts on bonds issued are amortized over the terms of the bonds using the effective interest method as a component of interest expense.

Debt defeasance charges result from debt refunding transactions and comprise the difference between the reacquisition costs and the net outstanding debt balances including deferred costs of the defeased debt at the date of the defeasance transaction. Such charges are in­cluded as a component of long-term debt and amortized as a component of interest expense over the shorter of the life of the refunded debt or the new debt, using the effective interest method.

Deferred Regulatory Asset and Credits The District’s Board has the authority to establish the level of rates charged for all District services. As a regulated entity, the District’s financial statements are prepared in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Ef­fects of Certain Types of Regulation, which requires the effects of the rate making process be recorded in the financial statements. Accordingly, certain expenses and income, normally reflected in operations as incurred, are recognized when included in rates and recovered from or refunded to customers as set forth in rate actions taken by the Board.

Self-insurance Liability Substantially all of the District’s assets are insured against possible losses from fire and other risks. The District carries insurance coverage to cover general claims in excess of $1,000 per occurrence, worker’s compensation claims in excess of $500 per occurrence and medical, dental and vision claims collectively in excess of $125 per employee. The District also has liability insurance for general claims in excess of $35,000. The District records liabilities for unpaid claims when they are probable of occurrence and the amount can be reasonably estimated. The accompanying financial statements include accrued expenses for general li­ability, workers’ compensation and medical, dental and vision claims based on the District’s best estimates of the ultimate cost of settling outstanding claims and claims incurred, but not reported. At December 31, 2005 and 2004, the District’s estimated self-insurance liability totaled $1,149 and $1,209, respectively, and is reported as a component of accounts payable and accrued expenses in the consolidated balance sheets.

Gas Price Swap and Option Agreements The District uses forward purchase agreements, swaps and option agreements to hedge the impact of market volatility on gas prices for its gas fueled power plants. Expenses under the contracts, net of the payments received, are reported as a component of generation and fuel

expense, in the period in which the underlying gas and power deliveries occur.

Derivative Financial Instruments The District records derivative financial instruments, consisting of gas swap price agree­ments, option agreements, and gas and electricity purchase and sales agreements that are not treated as normal purchases and normal sales, at fair value on its balance sheets with the corresponding entry recorded in the consolidated statements of revenues, expenses and changes in net assets. The fair values of gas price swap and option agreements are based on forward prices from established indexes for the applicable regions. The fair values of gas and electricity purchase and sales agreements are based on forward prices from established in­dexes from applicable regions and discounted using established interest rate indexes. While the District does not enter into agreements for trading purposes, it does not apply hedging accounting to these agreements. Therefore, the changes in derivative financial instruments are recorded as a component of generation and fuel expense.

The District reports derivative financial instruments with remaining maturities of one year or less and the portion of long-term contracts with scheduled transactions over the next twelve months as current on the consolidated balance sheets. The District is exposed to risk of nonperformance if the counterparties default or if the agreements are terminated. The District monitors these risks, and does not anticipate nonperformance.

Net Assets The District classifies its net assets into three components - invested in capital assets, net of related debt; restricted; and unrestricted. These classifications are defined as follows:

Invested in capital assets, net of related debt - This component of net assets consists of capital assets, net of accumulated depreciation reduced by the outstanding debt balances, net of unamortized debt expenses and unspent debt proceeds.

Restricted - This component consists of net assets with constraints placed on their use, ei­ther externally or internally. Constraints include those imposed by debt indentures, grants or laws and regulations of other governments, by law through constitutional provisions or enabling legislation or by the Board.

Unrestricted - This component of net assets consists of net assets that do not meet the defini­tion of “restricted” or “invested in capital, net of related debt.”

Board Designated Net Assets Net assets include amounts that the District’s Board designates as reserves for debt service, capital improvements and rate stabilization. The rate stabilization fund represents amounts reserved for the purpose of stabilizing electric utility rates in future periods. The Board determines the annual transfers into and out of these reserves. While the Board designates these funds as reserve funds, they are not restricted and the Board can utilize such funds for any purpose.

In 2004, upon issuance of the 2004 revenue bonds, the Board transferred $20,000 and $12,791 into the rate stabilization and capital improvements funds, respectively. Addition­ally in 2004, the Board transferred $7,240 out of the rate stabilization fund.

The designated funds included in net assets were as follows at December 31:

2005 2004 Rate stabilization $34,076 $34,076 Debt service 16,661 26,543 Capital improvements 12,791 12,791

$63,528 $73,410

��

Purchased Power Expenses A portion of the District’s power needs are provided by power purchase agreements. Ex­penses from such agreements, along with associated transmission costs paid to other utilities, are charged to purchased power expense in the period the power was received. Adjustments to prior billings are included in purchased power expense once the payments or adjustments can be reasonably estimated. Gains or losses on power purchase and sale transactions that are settled without physical delivery are recorded as net additions or reductions to purchase power expense.

Contributions in Aid of Construction and Grants The District receives CIAC for customer contributions relating to expansions to the District’s distribution facilities. The District also receives grant proceeds from federal and state as­sisted programs for its River Restoration programs and other programs. The contributions and grant proceeds are included in other income in the accompanying financial statements. When applicable, these programs may be subject to financial and compliance audits pursu­ant to regulatory requirements, although the District considers the possibility of any material grant disallowances to be remote.

Asset Retirement Obligations The District accounts for potential asset retirement obligations in accordance with Statement of Financial Accounting Standards No 143 (SFAS 143), Accounting for Asset Retirement Obligations, which sets forth accounting requirements for the recognition and measurement of liabilities for legal obligations associated with the retirement of tangible long-lived assets. Under SFAS 143, an obligation is recorded only when legally binding retirement obligations exist under enacted laws, statutes, written contracts or oral contracts, including obligations arising under the doctrine of promissory estoppel. Under this statement, asset retirement obligations (AROs) are recognized at fair value as incurred and capitalized as a component of the cost of the related tangible long-lived assets.

The District has identified potential retirement obligations related to certain generation, transmission and distribution facilities located on properties that do not have perpetual lease. The District’s nonperpetual leased land rights generally are renewed continuously be­cause the District intends to utilize these facilities indefinitely. Since the timing and extent of any potential asset retirements are unknown, the fair value of any obligations associated with these facilities cannot be reasonably estimated. Accordingly, no liability has been recorded at December 31, 2005.

Implementation of GASB Statement No. 40 In 2005, the District implemented SGAS No. 40 (GASB 40), Deposit and Investment Risk Disclosures - an amendment of GASB Statement No.3 SGAS No. 40 requires disclosure of credit risk, concentration of credit risk, interest rate risk, and foreign currency risk and modifies previous custodial credit risk disclosure requirements. Deposit and investment risk disclosures relating to 2004 balances presented in Note 5 have been modified to con­form to the new standard.

Recent Accounting Pronouncement In June 2004, GASB issued SGAS No. 45, Accounting and Financial Reporting by Employers for Post Employment Benefits other than Pensions (OPEB), which establishes standards of accounting and financial reporting for OPEB expense and related OPEB liabilities or assets. OPEB arises from an exchange of salaries and benefits for employee services rendered. It refers to post employment benefits other than pension benefits such as post employment healthcare benefits. The Statement is effective for the District beginning in 2007. The Dis­trict is currently assessing the new statement and has not determined the specific impact of

adoption. However, as described in note 11, the District’s estimate of its accumulated pen­sion benefit obligation related to its OPEB obligations is $6,400 at December 31, 2005.

Reclassifications Certain amounts in the 2004 financial statements have been reclassified in conformity with the 2005 presentation.

3. Utility Plant The summarized activity of the District’s utility plant during 2005 is presented below:

Balance Balance December 31, Transfers & December 31,

2004 Additions Disposals 2005

Nondepreciable utility plant Land $20,639 $79 $- $20,718 Construction in progress 148,194 138,420 (56,243) 230,371

Total nondepreciable utility plant 168,833 138,499 (56,243) 251,089

Depreciable utility plant Generation 172,859 517 (153) 173,223 Distribution 182,607 16,934 (738) 198,803 Transmission 52,027 867 - 52,894 General 49,709 1,665 (732) 50,642 Future power rights 25,671 98 - 25,769 Irrigation 44,266 1,437 (198) 45,505 Investment in gas properties - 34,646 - 34,646

Total depreciable utility plant 527,139 56,164 (1,821) 581,482 Less: accumulated depreciation,

amortization, and depletion (185,872) (15,936) 1,678 (200,130) Depreciable utility plant, net 341,267 40,228 (143) 381,352

Utility plant, net $510,100 $178,727 $(56,386) $632,441

The summarized activity of the District’s utility plant during 2004 is presented below: Balance Balance

December 31, Transfers & December 31, 2003 Additions Disposals 2004

Nondepreciable utility plant Land $20,015 $624 $- $20,639 Construction in progress 48,022 126,026 (25,854) 148,194

Total nondepreciable utility plant 68,037 126,650 (25,854) 168,833

Depreciable utility plant Generation 172,463 440 (44) 172,859 Distribution 170,053 15,147 (2,593) 182,607 Transmission 46,774 5,262 (9) 52,027 General 49,220 2,539 (2,050) 49,709 Future power rights 25,671 - - 25,671 Irrigation 42,644 1,841 (219) 44,266

Total depreciable utility plant 506,825 25,229 (4,915) 527,139 Less: accumulated depreciation and amortization (176,518) (14,360) 5,006 (185,872)

Depreciable utility plant, net 330,307 10,869 91 341,267 Utility plant, net $398,344 $137,519 $(25,763) $510,100

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Development project In 2002, the District began active development of the Walnut Energy Center power plant (the “Project”), a 250 MW natural gas fueled generation facility. The Project achieved com­mercial operation on February 28, 2006. At December 31, 2005 and 2004, the District’s cumulative construction and development costs related to the Project totaled $207,024 and $135,693, respectively. These amounts are included in Construction in Progress in the above tables.

4. Participation in Joint Powers Agencies Transmission Agency of Northern California The District is a member of the Transmission Agency of Northern California (TANC), a JPA consisting of fifteen municipal utilities. TANC is a participant, with a 79.3% share of the California- Oregon Transmission Project (COTP) and other facilities for electric power trans­mission. TANC develops, operates and manages these projects. The COTP provides electric transmission between the Pacific Northwest and California. The District has a 12.4% en­titlement share of TANC’s portion of the COTP and other facilities, which provide the Dis­trict with 154 megawatts (MW) of transmission during normal operating conditions. The District also has a 6.3% entitlement share of TANC’s transmission under the South of Tesla transmission agreements, which provide the District with 19 MW of transmission during normal operating conditions between Tesla and Midway.

Under the TANC agreements, the District is responsible for TANC’s development, operat­ing and debt service costs on a take-or-pay basis proportionate to its entitlement share. During 2005 and 2004, the District’s total expenses in connection with its TANC agree­ments, included in purchased power expense, totaled $4,744 and $4,935, respectively. At December 31, 2005 and 2004, the District has an affiliate obligation payable to TANC of $7,402 and $7,143, respectively, relating to certain non-cash expenses and other cumulative differences between expenses recognized for accounting purposes and cash payments made to the Agency.

Northern California Power Agency The District is a member of the NCPA, a JPA consisting of fifteen member agencies. NCPA develops and operates projects for the generation and transmission of electric power.

The District has a 6.3% entitlement share in the capacity and energy from NCPA Geothermal Plants l and 2 (the “Geothermal Project”). The District is responsible for development, op­erating and debt service costs on a take-or-pay basis in proportion to its entitlement share. The District’s expenses relating to the Geothermal Project, included in purchased power expense, were $4,902 and $5,504 in 2005 and 2004, respectively. At December 31, 2005 and 2004, the District has prepaid expenses related to the Geothermal Project to NCPA of $4,711 and $4,528, respectively, which is included in prepaid expenses and other current assets on the balance sheets.

The Geothermal Project continues to experience lower than expected steam production from the geothermal wells on its leasehold properties. Therefore, NCPA operates the facility at lower output levels than originally planned, which increases the cost of power per unit. Although the cost of power from the Geothermal Project is higher than that supplied from most other sources, the District is obligated to pay its contractual take-or-pay obligations under its agreement with NCPA until they are fully satisfied, regardless of resulting cost or availability of energy. Management plans to continue to include the Geothermal Project in its long-term resource plan and, as such, its related costs are fully recoverable in the District’s rates.

Financial Summary of NCPA and TANC The combined summarized financial information of NCPA and TANC is as follows at De­cember 31:

2005 2004 (unaudited) (unaudited)

Total assets $1,374,473 $1,415,860 Total liabilities $1,351,752 $1,400,031 Total net assets 22,721 15,829

$1,374,473 $1,415,860 Excess of revenues over

expenses for the year $15,591 $12,328

The long-term debt of TANC and NCPA is collateralized by a pledge and assignment of net revenues of each JPA, supported by the take-or-pay commitments of the District and other members. As such, the District is contingently obligated for its proportionate share of TANC’s liabilities of $481 and NCPA’s debt related to the Geothermal Project of $143 at December 31, 2005. Should other members of TANC and NCPA default on their obligations to these JPAs, the District would be required to make “step up” payments, up to 25% of its proportionate share, to cover a portion of the defaulted payments and would be entitled to the same proportion of additional power production or transmission.

Walnut Energy Center Authority The Authority is a 250 MW natural gas fueled generation facility that is blended into and reported as a component unit of the District. Through December 31, 2005, all of the Au-thority’s activities have related to the development and construction of the generating facility. Copies of Authority’s annual financial reports may be obtained from its Controller at P.O. Box 381017, Turlock, CA 95381. The Authority’s financial information is summarized as follows:

2005 2004 Current assets $12,535 $83,154 Non-current assets 258,464 149,850 Total assets $270,999 $233,004

Current liabilities $63,337 $24,988 Long-term debt 207,662 208,016 Total liabilities $270,999 $233,004

5. Cash, Cash Equivalents and Investments The District’s investment policies are governed by the California Government Codes and its Bond Indenture, which restricts the District’s investment securities to obligations which are unconditionally guaranteed by the U.S. Government or its agencies or instrumentalities; direct and general obligations of the State of California (State) or any local agency within the State; bankers’ acceptances; commercial paper; certificates of deposit; time certificates of deposit; repurchase agreements; medium-term corporate notes; shares of beneficial inter­est; mortgage pass-through securities; and deposits with the Local Agency Investment Fund (LAIF). Investments in LAIF are unregistered, pooled funds. LAIF is a component of the Pooled Money Investment Account Portfolio (PMIA) managed by the State Treasurer, in ac­cordance with Government Code Sections 16430 and 16480. PMIA funds are on deposit

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with the State’s Centralized Treasury System and are managed in compliance with the Cali­fornia Government Code, according to a statement of investment policy which sets forth permitted investment vehicles, liquidity parameters and maximum maturity of investments. The District’s deposits with LAIF comprise demand deposits up to $40.0 million maximum and amounts above $40.0 million are able to be withdrawn after a thirty day period. The fair value of the District’s investments in LAIF approximates the value of its pool shares.

The District’s investment policy includes restrictions for investments relating to maximum amounts invested as a percentage of total portfolio and with a single issuer, maximum ma­turities, and minimum credit ratings.

Credit Risk To mitigate the risk that an issuer of an investment will not fulfill its obligation to the holder of the investment, the District limits investments to those rated, at a minimum, “A1” or equivalent for medium-term notes and “A” for commercial paper by a nationally recognized rating agency.

Custodial credit risk This is the risk that in the event of the failure of a depository financial institution or coun­terparty to a transaction, the District’s deposits may not be returned or the District will not be able to recover the value of its deposits, investments or collateral securities that are in the possession of another party. The District does not have a deposit policy for custodial credit risk. At December 31, 2005 and 2004, deposits totaling $787 and $744, respectively, are insured by the Federal Deposit Insurance Corporation; cash, cash equivalents and invest­ments, excluding the LAIF, totaling $143,222 and $151,189, respectively, are collateralized with securities held by the pledging bank’s trust department in the District’s name; and investments in the LAIF at December 31, 2005 and 2004, of $26,781 and $70,987, respec­tively, were uninsured and uncollateralized.

Concentration of credit risk This is the risk of loss attributed to the magnitude of an entity’s investment in a single issuer. The District places no limit on the amounts invested in any one issuer for federal agency securities, except for mortgage pass through securities which may not exceed 20% of the District’s surplus money. The following are the concentrations of risk representing 5% or greater in either year:

Investment type 2005 2004 Cash 17% 13% LAIF 15% 31% Fannie Mae 40% 34% Repurchase Agreements 5% 2% T-Notes 14% 13%

Interest rate risk Though the District has restrictions as to the maturities of some of the investments, it does not have a formal policy that limits investment maturities as a means of managing its expo­sure to fair value losses arising from increases in interest rates. Of the District’s total portfolio at December 31, 2005 and 2004, all of the District’s cash and cash equivalents have maturi­ties of 90 days or less. The remaining investments mature between one to three years. The following schedules present the credit risk at December 31, 2005 and 2004. The credit ratings listed are from Standard and Poor’s. NR means not rated.

Credit Rating 2005 2004 Cash and cash equivalents:

Deposits NR $30,659 $30,701 Commercial Paper NR 2,269 -Treasury Notes TSY 6,175 -Fannie Mae AAA 5,154 5,155 Repurchase Agreements NR 9,543 -Local Agency Investment Fund NR 26,781 70,987

80,581 106,843 Short-term investments:

Fannie Mae AAA 12,119 34,200 Corporate notes AAA, AA-, A+ 1,619 2,064 Treasury Bills TSY - 6,209 Other Corporate Obligations NR - 6,394

13,738 48,867 Long-term investments:

Fannie Mae AAA 51,978 38,440 Treasury Notes TSY 17,845 23,333 Corporate notes AAA, AA-, A+ 6,647 5,437

76,470 67,210 $170,789 $222,920

General operating funds: Operating accounts $45,517 $9,367 Funds designated for rate stabilization 55,200 62,440 Funds designated for capital improvements 12,791 12,791

113,508 84,598 Restricted funds:

Construction funds 2,269 64,341 Reserve funds 34,665 26,325 Debt service fund 16,662 36,151 COP reserve funds 3,460 11,235 Other 225 270

57,281 138,322 $170,789 $222,920

The District maintains a rate stabilization fund to protect District customers from extreme rate increases that would otherwise be necessitated by dramatic short-term changes in pur­chased power or other operating costs. Annual transfers into and out of the fund are de­termined by the District’s Board of Directors (Board), which may utilize these unrestricted funds for any lawful purpose. The rate stabilization fund consists of an undivided portion of the District’s general operating funds. In 2004 the Board transferred $7,240 out of the rate stabilization fund.

In accordance with provisions of the credit agreements relating to certain of the District’s long-term debt obligations, restricted funds are maintained at levels set forth in the agree­ments to provide for debt service reserve and project funding requirements. These funds are held by trustees and are invested in U.S. Government securities and related instruments with maturities no later than the expected date of the use of the funds.

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900

6. Long-term Debt Long-term debt consists of the following at December 31:

2005 2004 Revenue bonds, fixed interest rates of 4.0%

to 7.3%, maturing through 2034 $277,245 $282,810 Revenue bonds, variable interest rates,

maturing through 2034 67,115 67,760 Certificates of participation, fixed interest

rates of 4.5% to 5.0%, maturing through 2033 26,785 26,785 Certificates of participation, variable interest

rates, maturing through 2031 37,400 38,300 General obligation bonds, fixed interest

rates of 3.5% to 5.5%, paid in full during 2005 - 1,490 Total long-term debt outstanding 408,545 417,145

Less: Current portion (7,360) (8,600) Unamortized premiums and discounts, net 8,872 9,507 Deferred losses on bond refundings, net (5,310) (5,993)

Total long-term debt, net $404,747 $412,059

Debt Issuance and Refunding In April 2004, the District issued 2004 Series A, B and C revenue bonds totaling $201,085, for the purpose of financing the construction of the Walnut Energy Center facility. The summarized activity of the District’s long-term debt during 2005 and 2004 are presented below:

Payments Amounts December 31, amortization December 31, Due Within

2004 Additions and refundings 2005 One Year

Revenue bonds $350,570 $(6,210) $344,360 $6,460 Certificates of participation 65,085 - (900) $64,185 900 General obligation bonds 1,490 - (1,490) $- -

Total 417,145 - (8,600) 408,545 $7,360 Less:

Unamortized premiums and (discounts), net 9,507 - (635) 8,872 Deferred losses on bond refundings, net (5,993) - 683 (5,310)

Total long-term debt, net $420,659 $- $(8,552) $412,107

Payments Amounts December 31, amortization December 31, Due Within

2003 Additions and refundings 2004 One Year

Revenue bonds $155,290 $201,085 $(5,805) $350,570 $6,210 Certificates of participation 65,985 - (900) 65,085 General obligation bonds 2,920 - (1,430) 1,490 1,490

Total 224,195 201,085 (8,135) 417,145 $8,600 Less:

Unamortized premiums and (discounts), net 2,863 7,168 (524) 9,507 Deferred losses on bond refundings, net (6,719) - 726 (5,993)

Total long-term debt, net $220,339 $208,253 $(7,933) $420,659

Variable Rate Debt The District’s variable rate debt bears interest at daily, weekly and monthly rates, ranging from 1.4% to 3.55% at December 31, 2005. The District can elect to change the interest rate period or fix the interest rate, with certain limitations. The variable rate bondholders have the right to tender the bonds to the tender agent.

The District has two letters of credit totaling $46,215 with a bank, which expire in April 2011. These facilities provide liquidity support for a portion of the District’s variable rate revenue bonds and all of the District’s variable rate Certificates of Participation (COPs). The remaining variable rate revenue bonds (issued in 2004) can be put only to the tender agent and do not require liquidity support. Principal draws on the letters of credit would be pay­able in accordance with the maturities schedules of the related revenue bonds and COPs. Accordingly, the District has recorded such bonds as long-term debt, less amounts sched­uled to mature within one year of the balance sheet dates. No amounts have been drawn on these letters of credit to date.

General The COPs and revenue bonds are collateralized by a pledge of, and a lien on, the revenues of the electric system after deducting maintenance and operation costs, as defined in the bond resolutions, subject to prior liens relating to the general obligation bonds. The District’s bond resolutions contain various covenants that include requirements to maintain mini­mum debt service coverage ratios, certain financial ratios, stipulated minimum funding of revenue bond reserves, and various other requirements.

The District has a surety bond of $4,102 with a bank, in lieu of funding reserve fund re­quirements for certain revenue bonds, as allowed by the bond resolution. The surety bond expires concurrent with the related revenue bonds. No amounts have been drawn on the surety bond to date.

Variable rate bonds totaling $46,215 may be subject to redemption at any interest date without a premium or discount. Fixed rate revenue bonds totaling $56,370 may be subject to redemption by the District in 2008 at a premium of 2%. Additionally, fixed rate revenue bonds totaling $58,300, $50,490 and $109,280 may be subject to redemption at any inter­est date, 2013, and 2014 respectively, by the District without premium or discount.

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The District’s scheduled future annual principal maturities and estimated interest are as fol­lows at December 31, 2005:

Estimated Principal Interest Total

2006 $7,360 $18,623 $25,983 2007 10,040 18,199 28,239 2008 10,775 17,629 28,404 2009 11,215 17,007 28,222 2010 12,480 16,334 28,814 2011-2015 70,895 72,718 143,613 2016-2020 74,170 57,322 131,492 2021-2025 78,715 39,690 118,405 2026-2030 73,825 22,536 96,361 2031-2034 59,070 6,478 65,548

$408,545 $286,536 $695,081

The District used the interest rates in effect as of December 31, 2005, to estimate the future interest requirements for its variable rate debt, included in the table above.

At December 31, 2005 and 2004, the estimated fair values of the District’s long-term debt, calculated by determining the net present value using appropriate maturity dates of future debt service payments discounted at the bond buyer’s revenue bond index rate, are as fol­lows:

2005 2004 Carrying amount $412,107 $420,659 Fair value $414,318 $431,532

7. Commercial Paper In 2005, the District issued commercial paper notes to finance capital expenditures. The effective interest rate for the notes outstanding at December 31, 2005 was 4.1% and the average term was 30 days. The District maintains a $64.5 million letter of credit to support the sale of these outstanding notes and incurs an annual fee for this service. There has not been a term advance under the letter of credit.

The summarized activity of the District’s Notes during 2005 is presented below:

Balance at Balance at beginning of end of

Year Additions Reductions Year December 31, 2005 $ - $52,569 - $52,569

8. Regulatory Deferrals The District’s Board has taken various regulatory actions that result in differences between recognition of revenues and expenses for rate-making purposes as reflected in these consoli­dated financial statements, and as incurred. These actions result in regulatory assets and credits.

Deferred Regulatory Assets Deferred regulatory assets consist of the following at December 31, 2005:

2005 2004 Westside facility costs $611 $1,902 Unrealized loss on investments 1,320 989

$1,931 $2,891 Westside facility costs

Certain costs incurred in connection with the Westside facilities acquisition from PG&E in December 2003 are being recovered as part of a surcharge the District includes in the rates collected from the Westside retail customers. The balance is amortized through col­lections.

Unrealized Losses on Investments

The District defers unrealized holding gains and losses on its investments until such invest­ments mature or are sold which is consistent with the District’s rate setting process.

Deferred Regulatory Credits Deferred regulatory credits consist of the following at December 31:

2005 2004 Electric rate stabilization $21,124 $21,124 Public benefit 3,566 2,480

$24,690 $23,604 Electric Rate Stabilization

Prior to 2003, the District deferred interest earnings on net assets designated for electric rate stabilization. These amounts will be amortized as increases in retail revenues in future periods based on a rate program approved by the Board of Directors which releases rate sta­bilization amounts under identified circumstances when power supply costs are significantly higher than the cost estimates included in rates.

Public Benefit

In February 2003, the District’s Board identified a specific component of its rates, 2.85%, to be committed to public benefit expenditures. During 2005 and 2004, the District’s public benefit expenditures were less than the amount collected in rates. As a result, the District has deferred the unexpended revenues of $3,566 and $2,480 at December 31, 2005, and 2004, respectively.

Public benefit expenses consist of non-capital expenditures for energy efficiency programs and renewable energy resources.

9. Derivative Financial Instruments The District enters into contracts for the purchase of electricity to meet the expected needs of its retail customers and for the purchase, transportation and storage of natural gas to meet its generation needs. The District also enters into hedging transactions to reduce the price volatility of some of these agreements. Certain of these contracts are classified as derivative financial instruments.

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The fair value of the District’s derivative financial instruments are as follows: December 31,

2005 2004 Derivative Financial Instrument Assets:

Gas related contracts $9,257 $1,462 Electric related contracts - 975

Total current derivative financial instruments $9,257 $2,437 Derivative Financial Instrument Liabilities:

Gas related contracts $3,554 $1,414 Electric related contracts 2,399 182

Total derivative financial instruments 5,953 1,596 Less: current portion 4,815 1,596

$1,138 $-

10. Pension Plan The District has a single-employer group defined benefit pension plan (the “Plan”) which provides retirement benefits covering substantially all its employees who have completed one year of continuous service. Employees may retire after age 55 with benefits based on compensation and years of service to actual retirement date. The Plan also provides death benefits for those employees having reached age 55.

The District is the administrator of the Plan and through the action of its Board, may amend or establish Plan provisions. The Board has appointed a third party to carry out certain administrative responsibilities. The Plan is a governmental plan under section 414(d) of the Internal Revenue Code (IRC). Copies of the Plan’s annual financial report may be obtained from the District’s executive office at 333 East Canal Drive, Turlock, California 95381.

Funding Policy To participate in the plan, employees who are not members of a bargaining unit are required to contribute 1.25% of their earnings and employees who are members of a bargaining unit are required to contribute 2.25% of their earnings. Under the Plan provisions established by the Board, the Plan is to be funded in amounts equal to the normal costs of the Plan plus an amortization of the past service liability. Contributions made by the employees’ vest imme­diately. Contributions made by the District are fully vested after five years of participation.

Annual Pension Cost The annual required contributions for 2005 and 2004 were determined by actuarial valua­tions using the frozen entry age actuarial cost method. The actuarial assumptions included the following for 2005 and 2004:

• Investment rate of return applied to assets of 8.5% per year;

• Discount rate applied to the pension benefit obligation of 8.5% per year;

• Salary increases of 4.5% per year; and

• Cost of living adjustment of 3.5% per year.

Realized and unrealized gains are phased in to the actuarial value of Plan assets over a three year period, and may be adjusted so that the assets are not less than 80% or more than 120% of the fair market value of the Plan’s assets as of the current valuation date. The unfunded actuarial accrued liability is being amortized as a portion of annual pension cost.

The District’s annual pension cost and net pension obligation or prepaid for 2005 and 2004, based on valuations as of December 31, 2005 and 2004, respectively, were as follows:

2005 2004 Annual required contribution $5,335 $4,557 Interest on net pension obligation 106 -Adjustment to annual required contribution (142) -

Annual pension cost 5,299 4,557 Contributions made 5,654 3,314

Increase (decrease) in net pension (obligation) prepaid 355 (1,243) Net pension (obligation) prepaid, beginning of period (1,240) 3

Net pension obligation, end of period $(885) $(1,240)

Summarized Historical Trend Information Three year trend information is presented below:

Net Fiscal Annual Percentage Pension Period Pension of APC (Obligation) Ending Cost (APC) Contributed Prepaid 12/31/05 $5,299 107% $(885) 12/31/04 $4,557 73% $(1,240) 12/31/03 $3,387 79% $3

The supplemental schedule of funding progress is presented below: Actuarial Actuarial Accrued Unfunded UAAL as a

Actuarial Value of Liability (AAL) AAL Funded Covered Percentage of Valuation Assets Entry Age (UAAL) Ratio Payroll Covered Payroll

Date (a) (b) (b-a) (a/b) (c) ([b-a]/c)

12/31/05 $102,136 $132,592 $30,456 77.0% $25,508 119.4% 12/31/04 $95,190 $123,498 $28,308 77.1% $23,863 118.6% 12/31/03 $94,299 $116,216 $21,917 81.1% $23,130 94.8%

11. Other Post Employment Benefits The District provides post-retirement health care benefits in accordance with District policy to qualified retirees and their spouses. The qualification requirements for these benefits are the same as those under the District’s Plan. The District contributes the full cost of coverage for retirees; however, retirees contribute the estimated health care cost for dependents. Cov­ered retirees are also responsible for personal deductibles and co-payments. Currently, 80 retirees and surviving spouses are receiving benefits. The District pays for post-retirement health care benefits on a pay-as-you-go basis. During 2005 and 2004, the District’s post-re-tirement health care benefit expenditures were $331 and $467. At December 31, 2005, the District estimates the accumulated post-employment benefit obligation for the health care benefits plan is approximately $6,400.

In addition, the District offers its employees a deferred compensation plan (the “Deferred Plan”), which provides employees the option to defer part of their compensation until termi­nation, retirement, death, or unforeseeable emergency. The District has the duty of reason­able care in the selection of investment alternatives, but neither the District nor its directors or officers have any liability for losses under the Deferred Plan. The District holds all de­ferred compensation assets in the name of the Deferred Plan, and accordingly, the Deferred Plan assets and corresponding liability are not recorded in the accounts of the District.

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12. Commitments Power Sales Agreement The District has a power sales agreement with Merced Irrigation District (MEID) to sell ten MW of electricity on a take-or-pay basis. The District receives an energy payment based on a formula, as defined in the agreement, based in part on a California natural gas price index. The District also receives a capacity payment based on a formula, as defined in the agreement. MEID is also required to purchase electricity for its supplemental power requirements, based on current market rates as set forth in the agreement. Sales under this agreement totaled $23,184 and $18,480 in 2005 and 2004, respectively. The agreement expired at the end of 2005 and was replaced with a new agreement with similar terms for 2006 and 2007 with a one time option to extend the agreement through April 30, 2008 at the sole discretion of MEID

Power Purchase Agreements The District has four long-term power purchase agreements with other power producers to purchase capacity and associated energy to meet its load requirements, which expire through December 2018. Capacity and certain energy is purchased on a take-or-pay basis. Power purchased under these agreements totaled $52,695 and $49,153 in 2005 and 2004, respectively.

City and County of San Francisco The District and the City and County of San Francisco (CCSF) have a power sales agreement (PSA) which allocates a share of excess Hetch Hetchy Project capacity and energy to the District, through 2015. The District purchased $9,091 and $5,364 of power in 2005 and 2004, respectively, under the CCSF agreement.

CCSF submitted a notice of contract termination to the District effective February 2004, at which time CCSF ceased making power deliveries under the PSA. Negotiations to enter into a new agreement were completed in April 2005. This agreement ended firm sales at the end of 2005, but provides the District with energy, as available, for its eligible loads and ad­ditional excess energy when available. The new Power Purchase expires in 2015.

Gas Purchase Agreements The District has two long-term natural gas supply agreements with two companies to meet the consumption need of its natural gas fired power plants. The District can purchase up to 27,000 million British Thermal Units (MMBtu) per date from one counterparty, the other contract allows for the purchase of all required natural gas for the Walnut Energy Center not to exceed 55,000 MMBtu per day. Pricing for both contracts are indexed to certain natural gas indexes, as defined in the gas purchase agreements. Fuel purchased under both agree­ments totaled $10,488 and $2,375 in 2005 and 2004, respectively.

Gas Transportation Capacity and Storage Agreements The District has nine long-term gas transportation capacity agreements and one long-term gas storage agreement with Canadian and U.S. companies to transport natural gas to the District’s natural gas fired power plants from gas supply basins in Alberta, Canada. The gas transportation capacity agreements complement the District’s gas purchase agreements, described above, and expire in years 2006 through 2033.

The approximate future minimum obligations for the above described power purchase, gas supply, and gas transportation and storage contracts are as follows at December 31, 2005:

Amount 2006 $19,972 2007 20,228 2008 20,492 2009 20,546 2010 20,892 Thereafter 182,462

$284,592

13. Contingencies California Energy Market Refund Proceedings In July 2001, FERC issued an order establishing evidentiary hearings for the purpose of determining the amount of refunds, if any, due to customers of the California ISO and PX organized spot markets from market participants selling into those markets for the period October 2, 2000 through June 20, 2001 (the refund period). During this time period, the District was both a seller and a buyer in the markets. The Administrative Law Judge (ALJ) assigned to the proceedings adopted hearing procedures for a three-phase hearing. Phase 1 of the hearing, held in March 2002, addressed the calculation of the price to be applied to sales into the California ISO and PX market retroactively. Phases 2 and 3 addressed the cal­culation of refunds and identification of the amount currently owed to each supplier (with separate quantities due from each entity) by the California ISO, the investor owned utilities, and the State of California. Hearings on Phases 2 and 3 concluded in August 2002.

In December 2002, the ALJ issued his Certification of Proposed Findings (the “Findings”) for all three phases and found that the District owes $1,243 in refunds for these sales. The Dis­trict has appealed to FERC to overturn the Findings regarding lack of jurisdiction over the refunds owed by the District. In addition, the California parties have appealed the Findings to FERC and are requesting that FERC significantly increase all sellers refund liabilities.

In March 2003, FERC revised its ruling to include the impact of gas price mitigation to be applied to sales into the California ISO and PX market retroactively. In July 2004, the Cali­fornia ISO completed the calculation of revised Mitigated Market Clearing Prices (MMCPs) for the refund period using the methodology that had been developed by the administrative process at FERC, including mitigated gas pricing. The District’s refund liability under the new MMCPs increased to approximately $3,600.

On September 6, 2005 the Ninth Circuit Court of Appeals issued its decision regarding FERC’s authority regarding the imposing of refunds on non public utilities. The Court concluded that FERC does not have authority over non public authorities making sales in wholesales energy markets.

In any event, the District does not expect to be liable for any refunds because the District’s fi­nal refund liability, if any, would likely not require a cash payment; rather it would probably be fully set off against amounts owed by the California ISO to the District of $4,340. The District has recorded an allowance of $3,820 against the amount owed by the California ISO related to the uncertainty of the ultimate amount that it will collect. The District believes such allowance is sufficient to cover its refund obligation, if any, and accordingly, no liability has been recorded.

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California Parties vs. Government Entities Complaint for Damages for 2000 and 2001 Power Sales Following the 9th Circuit Court of Appeals ruling that FERC could not order refunds in the California Refund proceeding, the District and other publicly owned utilities were sued in US District Court on March 16, 2006, by Pacific Gas and Electric Company, California Edison Company and California Electricity Oversight Board and on March 21, 2006, by San Diego Gas & Electric (collectively the “California Parties”). The claims are for damages arising from sales of wholesale power and ancillary services from May 1, 2000 through June 20, 2001. No actual dollar damage amounts were cited in the complaints. The complaints state they are based upon the same facts as were included in the FERC and 9th Circuit Court cases. However, unlike the California Refund proceeding, the complaints extend the period in dispute back five months making the starting date May 1, 2000, instead of October 2, 2000. During the May 1, 2000 through October 1, 2000 the District made no sales to the California ISO. Thus, the transactions in dispute in the California Parties’ Complaints are believed to be the same transactions in dispute in the California Refund proceeding before FERC. District management believes it is reasonably possible, but not probable, that the District will ultimately incur a liability in this matter due to the strength of its legal defenses and because these complaints are a result of the California parties defeat in the 9th Circuit Court of Appeals and addresses the same issues raised in those proceedings. As such, no liability has been recorded.

Potential dispute over Calpine Energy Services contract On December 22, 2000, the District entered into an 83-month Power Purchase Agreement (“Calpine PPA”) with Calpine Energy Services, LP (“Calpine”) to purchase up to 50 MW of Non-California ISO electricity beginning July 1, 2001. The Calpine PPA was originally to expire on May 31, 2008.

The Calpine PPA provided for discounts to the District when California ISO energy replaced Non-California ISO energy in excess of specified amounts. Between the execution of the Calpine PPA and the start of service, Calpine executed a Participating Generator Agreement with the California ISO and began scheduling all energy deliveries to the District with and through the California ISO.

As provided in the Calpine PPA and as permitted by applicable law, the District terminated the Calpine PPA for default as a result of Calpine’s bankruptcy filing, effective January 24, 2006. In connection with the termination of the Calpine PPA, the District netted payments due the District under the Calpine PPA against pending invoices from Calpine, as provided in the Calpine PPA and a separate netting agreement between the parties. Specifically, the District did not pay Calpine’s invoices for energy delivered in December 2005 of $3,289 and January 2006 of $2,132 under the Calpine PPA after netting them against larger sums owed by Calpine to the District under the Calpine PPA. Calpine is disputing the District’s right to terminate the Calpine PPA and has expressed its disagreement that payments made by the District should be refunded. In response, the District has asserted its position in writing to Calpine. The District has not recorded a liability for this disputed amount since management believes it will prevail in asserting its contractual rights to offset any amounts due in accordance with applicable law and the netting provisions of the various agreements between the parties.

Scheduling Coordinator Services Tariff Dispute In November 1999, PG&E filed its proposed Scheduling Coordinator Services (SCS) Tariff with FERC. The proposed SCS Tariff is designed to charge the District and other existing wholesale contract customers for the various scheduling services that PG&E purports to

provide. PG&E claims that such services were new services that were due to the advent of industry restructuring in California and the California ISO. Although PG&E’s Tariff filing was made in November 1999, PG&E was seeking to have the proposed SCS Tariff charges apply retroactively from April 1998 when the operations of the California ISO commenced and PG&E began incurring the ISO-related costs it is attempting to recover. In January 2000, FERC accepted for filing PG&E’s proposed SCS Tariff and set the matter for hearing. Since that time there have been several judicial proceedings on specific elements of the proposed SCS Tariff.

In June 2004, based on an order issued by FERC affirming PG&E’s SCS tariff, PG&E issued the District an invoice in the amount of $4,510. During 2004, the District paid the amounts in full, however, in 2005, PG&E and the District agreed on terms to settle the SCS Tariff charges dispute. The settlement agreement sets the District’s net obligation to be $3,700. As a result, a receivable from PG&E in the amount of $810 was recorded in the consolidated balance sheet at December 31, 2004, which was subsequently collected in 2005. The Dis­trict included the total net obligation under the settlement agreement as purchased power expense in the consolidated statements of revenues, expenses and changes in net assets in 2004.

In July 2005, the District of Columbia (D.C.) Circuit Court of Appeals issued a decision finding that the ISO Tariff required PG&E to recover the above-referenced cost differentials under either PG&E’s Transmission Owner Tariff (TO Tariff) or through bilateral negotia­tions to reform the existing contracts. On December 20, 2005, in light of the D.C. Court of Appeals decision, the FERC issued a remand order terminating the SCS Tariff proceeding. While the December 2005 FERC decision terminated the SCS Tariff proceeding, the District does not believe that this affects the settlement agreement.

General Contingencies In the normal course of operations, the District is party to various claims, legal actions and complaints, including possible liability for environmental matters. Although the ultimate outcome of these matters is not presently determinable, the District’s management believes the resolution of all such pending matters will not have a material adverse effect on the District’s financial position or results of operations.

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2005 Board of Directors Advisors Michael C. Berryhill Griffith & Masuda

President General Counsel

Michael V. Crowell PricewaterhouseCoopers LLP

Vice President Independent Accountants

Charles Fernandes Public Financial Management, Inc.

Member Financial Advisor

Randy Fiorini R.W. Beck, Inc.

Member Consulting Engineers

Phillip N. Short

Member Revenue Bond Ratings

2005 Management Team Moody’s A1

Fitch A+

Larry W. Weis Standard & Poor’s A+

General Manager

Randy C. Baysinger

Assistant General Manager, Power Generation

Casey J. Hashimoto For additional information, contact:

Assistant General Manager, Engineering & Operations Turlock Irrigation District

Joseph E. Malaski Public Information Office

Assistant General Manager, Financial Services & Treasurer P.O. Box 949

Martin J. Purdy Turlock CA 95381-0949

Assistant General Manager, Human Resources (209) 883-8448

Robert M. Nees www.tid.com

Assistant General Manager, Water Resources & Regulatory Affairs

Steven E. Boyd

Assistant General Manager, Consumer Services & Government Relations

Design: Martino Graphic Design, Inc. / Modesto, CA • Printing: Parks Printing / Modesto, CA

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GM Admin. General Manager

Executive Secretary to the General Mgr Carolyn Mendonca

ning Manager

Consumer Services &

Admin. AGM, Steve Boyd Adminstrative Asst. - General Mgr

Dept. Asst. Janice French

Manager Jennifer Stone Area Manager

Kate Schulenberg Public Information Officer

Public Benefits Program Analyst Nancy Folly Education Specialist

Customer Service Dept.

Dennis Swisher Customer Service Systems Analyst

Manager Rick Roe Field Service Rep.

James Mitchell Steve Lancaster Paul Cooper Dave Pontes Kirk Fink Arvery Shelton Meter Reader James Riley

Hershell Phillips Jim Carlson

Jacob Martinez Garrett Lucas Jason Heckman Edward Miller Darren Merenda Consumer Services & Government Relations Admin. Customer Service Dept.

Heidi Collins Rep. I-II

Deborah McCurdy Kim Rice Lisa Ladd

Sandra DeCasso Sergio Aguilar

Maria Paniagua Nobelia Howard Amber Patterson Dana Ortolan Candice Johnson Bety Rea

AGM, Martin Purdy Dept. Asst. Susan Carmichael Human Resources Analyst I - II

Adam Bolanos Benefits Coordinator Maureen Kramer Human Resources

Charlotte Dutra

Coordinator Mary Collum Financial Services Admin. AGM, Joe Malaski Administrative Asst.

Accounting Dept. Manager Martin Qualle Risk Investment Analyst Don Swanson

Diana Garcia Senior Accountant Inger Satterfield Irene Azevedo Christina Drumonde Payroll Accountant

Debbie Fisher Debra Larson

Kary Hansen

- Cashier Dana Dunkirk Customer Service Rep. I-II - Cashier Bobbi Babb

Rachel Partida Jenifer Miller Renee Cardona Erica Mapes Carlos Araujo Financial Services Admin. Information Services Dept. Information Services

Dept. Asst. Debra Azevedo

David Cummerow

Database & Network Administrator Andrew Postma

Software Engineer Keith Skelly Andrew Souza

Debra Knoll Ashish Raje Systems Analyst David Espos Mari Blanco David Arounsack

Kathy Jackson Jenny Martin

Help Desk Analyst I-II Jason Fox Bryan Blair

Materials Management Dept. Materials Management Dept. Mgr Alison Bryson Dept. Asst.

Senior Buyer Donna Ford David Barr Michael Hubble Buyer Robin Sanders Raymond Perez

Diane Rowley

Alan Adams

Brian Nord

Steve Mello

Administrative Asst. Diane Sawyer

Dept.

James Farrar Principal Energy Scheduler William Bacca Energy Scheduler I-II Gretna Soza Goretti Brown Jessie Garcia Jon Satterfield Mark Corbett James Norwood

cian I-II Leslie Bucheli Utility Analyst I-II Mike Brommer Amy Petersen Michelle Gonzales Joayne Miranda Resource Planning Dept.

Willie Manuel Utility Analyst I-II Chris Poley Thomas King

tions Admin. AGM, Casey Hashimoto Administrative Asst. Patsy Ormonde Administrative Asst. Sheila Mayo

Dept. Asst. Diane Pickering

neering Dept. Electrical Engineering

Brian LaFollette Senior Electrical Engineer

Senior - Electrical Engineering

Mark Selby Supervising Engineering

Engineering Pablo Rodriguez Les Barrigar

- Elec. I-II Judy Silva Steven Chambers

Aaron Donahue David Porath

Senior Energy Specialist Steve Hibbard Environmental Health &

Manager Rich Eastman Environment Health & Safety Specialist Richard Reece

tions Admin. Power & Communications Engineering Dept. Electrical Engineering

Larry Gilbertson Senior Electrical Engineer Rhett Calkins Esteban Martinez Randy Erickson Howard Shapiro Asst. Electrical Engineer Karl Kobrock

Senior - Electrical Engineering Mario Zavala Chris Miller Gordon Morimoto

- Elec. I-II Edward Jobe

Fleet & Plant Services

Rick Myers Fleet & Plant Services Analyst Jason Hicks Fleet & Plant Services Supervisor Mike Lucas

cian Michael Hardin Matt Lopes David Delco James Whitaker Adam McKinstry

Daniel Kenyon James Johnson

Daniel Lino

Loren Peterson Clyde Rodrigues

tions Admin. Line Dept. Line Dept. Manager

Dennis Moon Dept. Asst.

Kenneth Olson

Line Supervisor Michael Green

Brian Skonovd Dennis Larsson Stephen Brazil Ken Gross Ken Gibson Rick Brenes Electrical Lineworker Steve Stout Stephen Pinkney Ross Phillips Glenn Kaiser John Nelson Richard Lane Pete Bougoukalos Dennis Mattos Dave Boyer Alfred Borges Ron Duncan Robert Moore Bill Stavrianoudakis Gregg Campodonico Heath Schab Jan Backstrom

tions Admin.

Apprentice Electrical Lineworker Bryan Lovio Mike Nixon Dustin Krieger Aaron Baker Duarte Xavier Dan DeSomma James Small Thejon Baza Steve Johnson Michael Patterson

Derek Gambel Casey Guinn Denver Hodges Layton McDonald Joshua Sears Administrative Clerk I-II

Renee Cargill

Chuck Freeman Robert Chambers Apprentice Meter

Mario Castrejon

Adam Hope

Roger Parks

Gary Dutey

Anthony Lorenzo

Ignacio Alcorcha

Electrical Lineworker Ron Johnson Mark Pickens

Dispatcher Nancy Chambers

tions Admin.

tions Dept

Sam Postma Dept. Asst. Mary Angel

Substation & Comm

Scott Bullard Substation Supervisor Kurt Roberts Don Dunbar

James Butland Randy Wilkey Apprentice Substation

Manuel Thomas

Mike Bradley Jimmy Emmons Roger Moitoso Robert Middleton Electronic Supervisor Mike Fultz

Brad Arnold Ken Mello John Boyles Apprentice Electronic

Daniel Barkhousen Energy Mgmt. System

Energy Management System Supervisor John S. Souza

Paul Rodrigues

tions Admin.

ing Dept.

- Special Projects Ron Butcher

Manager Robert Anderson Power Control Center Operator Kraig Stockard R. Dwayne Nyberg H. Lee Million James Sisco

Karl Morton

James Mapes Appr Power Control Center Operator

Appr Power Control Center Operator Bart Sargenti Appr Power Control Center Operator Edward Sharp Appr Power Control Center Operator

Appr Power Control Center Operator James Strika Power Generation Admin. AGM Randy Baysinger Administrative Asst. Gail Humphrey Power Plant Engineering

Dept.

George Davies Dept. Asst. Momi Souza

bined Cycle Jay Brooks Mike Johnson

John Bales Anthony Chapin Sebastian Lub Johnny Cole Frank Carter

Dru Stewart James Anderson Ruben Castrejon Darryl Cully Instrument & Controls

Apprentice Instrument &

Mike Hines John Dunn

Rick Fortado Almond Power Plant Power Plant Super - Combined Cycle Devin Chapin

Nile Brundage

Paul Kayser

Apprentice Power Plant

Darin Dubel Sam Mettler Ray Newman Instrument & Controls

Ray Thomas Power Generation Admin.

Marty Rojas Power Plant Supervisor - Don Pedro Myron McCoy

Dean Gordin Reggie Knott Chris Martin Carl Stange Power Plant Supervisor - Small Hydro Russell Fox

Ron Lema Mark Brennecke Don Andersen Apprentice Power Plant

Lorenzo Sanchez

AGM Robert Nees Administrative Asst. Maria Faria

Manager Debbie Liebersbach

Keith Larson

Dist I-II Paul Posson Aquatic Biologist I-II

Civil Engineering Dept. Mgr Wilton Fryer Dept. Asst. Joyce Machado Senior Civil Engineer Brent Harrison Associate Civil Engineer

- Civil

Alejandro Buenrostro

- Civil I-II Marina Cummerow

Rudy Brunsvold Frank Leandro

- Civil I Carla Couto

Manager David Falkenberg

John McGowan

Don Pedro Recreation Agency

Carol Russell Dept. Asst. - DPRA

Customer Service Rep. I-II - Cashier Linda Shepherd

David Jigour Richard Martin Chief Ranger Roy Kroeze James McCoy Ranger I Marsha Fontana Steven Brown Kelly Gobel Brannon Gomes Peter Becchetti Robin Whitson

Manager Bill Flanagan

Claude Haugen Park Maintenance

Joseph Brooks

nance Dept.

Keith Cargill Dept. Asst. Stephanie Martinez Improvement District

Craig Clark

Robert Caetano Pest Control/ Facilities Manager Steve Marklund

Dwayne Nordell Pump Repair Supervisor Rick Wisdom

Louie Pombo Equipment Operator Donald Smith Ramon Martinez Brian Dias Frank Rice John Damas Crew Supervisor Kennard Schroeder Larry Prada Gene Mendoza Dale McElhaney

Gary Manson Larry Cabral

Glen Joslin

James Simpson Russell Silva Jerry Russell

Jose Colon Daniel Alexander

nance Dept.

John Phillips Kevin Greener

Christian Hooper

Alberto Gonzalez Micah Kaiser Luis Murillo

Joseph Oliveira Jacob Johnson Zachary Azevedo Gary Cordell Adam Alstadt Custodian Larry Crawford Robert Hayes Joshua Overman

Jerry Emig Dept. Asst.

Manager Charles Blocher

Mike Kavarian - La

Grange Mario Jones Ben Blazzard Customer Svc Rep I-II

Stella Lorenzo Emily Padilla

Operator John Hacker Bill Beets Joe Sequeira Kimberly Studley Bill Caudle Antone Perry Renaldo Winzey Joe English Ronald Beebe Allen Babbitt James Bollinger John Gregory Dan White Ray Mendonca Darrell Monroe Scott Burch Dennis Sego

Larry Smith

Sam Pierce

Operator

Bill Reichle Scott Cole Robert Alberti Marvin Medeiros Keith Nydam

Jim Griffin Mike Shaver Frank Cardoso Gary Doerksen Mark Jones Brian Fitzgerald

Larry Weis

Strategic Issues & Plan­

Wes Monier

Government Relations

Tami Wallenburg

Governmental Affairs

Mary Jo Talbot

Tony Walker

Tom Munoz

Dept. Mgr.

Lauretta Ayers Customer Service Div. Mgr. Tena Falkenberg Field Services Div.

Ted Mensonides

Ray Valenzuela

Colby Torres

Sr. Rep. Tracy Jones Tina Zamaroni

Sylvia Van Hook Sandra Woodward Rosemary Tobin

Tara Martinez Yuri Herrera

Human Resources Admin.

Lynn Clay

Technician

Workers’ Compensation

Rosemary Vierra

Accounting Div. Manager

Sr. Accounting Technician

Accounting Technician

Sr. Customer Service Rep.

Lynn Hallum

Dept. Mgr. Wayne Turnbow

I S Applications Mgr.

I S Operations Mgr. Bill Worsham

Jeffrey Leal

Information Svcs Opera­tions Tech. I-II

Venessa Roberts

John Waayers

Tracy Pombo

Purchasing Technician

Warehouse Supervisor

Warehouseperson Grady Weston Gary Youngdale Jeff Rocha

Utility Worker

Energy Resources Admin. AGM, Ken Weisel

Trading & Schelduling

Trading & Scheduling Dept. Mgr.

Energy Resources Techni­

Mgr.

Engineering & Opera­

Standards & Line Engi­

Dept Mgr.

Greg Tucker Engineering Technician

Kirk Tabar Warren Graham

Technician - Electrical

Engineering Technician

Jeff Sahlstrom

Jeffrey Anderson

Safety Div.

Engineering & Opera­

Dept Mgr.

Engineering Technician

Engineering Technician

Fleet & Plant Services Div.

Div. Mgr.

Fleet Equipment Techni­

Tim Unruh

Fleet Service Worker

Journey Layout & Fabrica­tion Welder

Engineering & Opera­

Wade Cockrell

Heidi Topete Job Scheduling Supervisor

Line Div.

Ron Vasconcellos

Troy Borges Engineering & Opera­

Line Div.

Michael Van Egmond

Donna Taylor Service Div. Service Div. Supervisor

Meter Technician

Technician

Randy Watts

Transformer Technician

Electrical Troubleshooter

Gerald Weese

Stephen Verschelden

Jeffrey Sturm

Electrical Trouble

Engineering & Opera­

Maintenance & Opera­

Maintenance & Opera­tions Dept. Mgr.

Substation & Communica­tions Div.

Div. Mgr.

Substation Technician

Technician

Guillermo Avalos

Electronic Technician

Technician

Support Div.

Electronic Technician

Engineering & Opera­

Special Projects Engineer­

Elec. Eng. Dept. Mgr.

Power Control Center Div. Control Center Div.

Gerald Avila

Tom Souza

Gary Weimer

Scott Ward

Dept. Mgr. Jeff Barton Combustion Turbine

Combustion Turbine Dept. Mgr.

Walnut Energy Center Power Plant Supr - Com­

Power Plant Tech - Gas Turbine

Michael Worley Apprentice PPT-GT Zachary Woody

Technician Jeffrey Warner

Controls Tech

Warehouseperson

Power Plant Tech - Gas Turbine

Rick Walters

Neil Taylor Joel Toledo

Tech - G.T. Kevin Woodhead

Technician

Hydro Div. Hydro Div. Manager

Power Plant Technician

Power Plant Technician

Technician

Water Resources & Regu­latory Affairs Admin.

Water Planning Dept.

Water Resources Analyst

Engineering Tech. - Water

Tim Ford

Tou B. Her Super. Engineering Tech

Todd Troglin Engineering Technician Sr. - Civil

Engineering Technician

Arie Vander Pol

Engineering Technician

Survey/Right of Way

Surveying Technician II Merle Wagner Surveying Technician I

Water Resources & Regu­latory Affairs Admin.

Recreation Dept. Mgr.

Susan Vanderschans

Recreation Div. Mgr.

Park Maintenance Div.

Sewer/Water Treatment Technician

Worker II

Water Resources & Regu­latory Affairs Admin. Construction & Mainte­

Mgr.

Trouble Shooter

Equip. Operation Div. Mgr.

Gunite & Pipeline Mgr.

Heavy Equipment Oper. Terry Autrey

Richard Taylor

Tim Isley

Maintenance Worker II

Chano Tovar

Water Resources & Regu­latory Affairs Admin. Construction & Mainte­

Maintenance Worker II Lew Wall

Tim Van Fleet Maintenance Worker I

Andrew Webb

Water Resources & Regu­latory Affairs Admin. Water Distribution Dept. Mgr.

Pam Yettman Water Operation

Aaron Turney Water Records Manager

Engineering Tech. Sr.

- Water Resources

Water Distribution

Gustavo Villarreal

Tony Harrewyn

Water Resources & Regu­latory Affairs Admin. Water Distribution Dept. Water Distribution

Wes Miller

Thomas Bagdanoff Terry Small Chris Yialouris

Kenny Virden

2005 TID Valued Employees