3F0404-06, 2003 Annual Financial Reports. Orlando Utilities Company - Page 16 of Notes to Consolidated Financial Statements
| ML041240099 | |
| Person / Time | |
|---|---|
| Site: | Crystal River  |
| Issue date: | 04/19/2004 |
| From: | Powell S Progress Energy Florida |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| 3F0404-06 | |
| Download: ML041240099 (75) | |
Text
Creating The Right nviroNnr cnt The Reliable One
-COMBINED.FINANCIAL,HIGHLIGHTSti:,.-'-.
6 I tk venues $ V.` i559,713 75 ting expenses 406, 15 1N)
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-,; otm 6 007 Interest an 9, 5 06
_E_7-In'te-r'e'st an 35 -440
-Income 55,01 025 _Fl Annuzi -di 2,S )91 8 200 Utilit'bla 06 748
--;5..;]l'--Tbtal 6sse 486,249 3 Long net--, ;260,061 ;281;'333 690,1 41 657,767- Z nor:, 56A 1;'AA' De t servicie coverage: z
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attached d debt-,.Aj_.
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-.13 perating revefidestu W R: ';513,409..?_t $ "453,'887
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-W 577i7O; 221193 00&afng expenses excludi66 fil6l -1 82 -991 -179,341 J - Tin! -W
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FINANCIAL"'HIGHLIGHTS Fz dMi nl'z O'perating revenu es'c KW46304!- rt - _7 perating expenses'4- -j "38 823 V2' K N az E-'-_-L--z
",,,-_',ELEc rRIG STATISTICAUHIGHLIGHTS 7 6 a 387,943A21_
k:lbtal sales (MWH) M4r Algorithms-! i'i V., --,-,7,030,393 r' T ota IFtjili616( MVVH) a U6 61TE e.'Aes (MWH) 2 292,408 V- "N
'W__TbtalbctiV6 services t-l 56,574 y x Average an ua residehtial'iJs6'(KWH);, 3-x 12,464IL
.zl TE!Ern-Aragefesi&ntjal revenue per KWH J_ "MOV-.1 &OU Heating eg dlay's'- 57 U i. da Y,,
r j 487 ooing egree.. ysyX, ;a`
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_,7,.Gross peakde-mand (MW):_-I--'T--4-'i"7 10 79 058-5"
,120 6 verage anhual iesidehtial 151,000 4
- ,Average reside 6606i-,1000'g11m
- 4-rl-" $ '70 Y, k56 116ififall (ifich6s)*; 56 66t,
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"T 11; Contents Income Before Contritions In Miin of Do" r Executive Overview 2 1993 0 uCooling 4 z 2003 6 15 20 25 30 35 40 45 OUConvenient Lighting 6 Qp erat Revenues In Mi ions of DoLasE Power Resources 8 1993 Energy Delivery 10
$559.7 2003 I I H 2 0UC 12 I i5 2 a 3II I I a I 0 50 100 150 200 250 300 350 400 450 500 550 600 IT, Marketing, Corporate Services 14 lectic Sales nino d MegawattHour Senior Management 16 a Commnssioners 18 I II I8 a 9. :105 :11 12 A 2003 Audited Financial Statements A-1
- of GaL ons Co' ANNUAL REPORT 2003 0
I I reating he Right
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Fnvirorirnent For II...qfmw 4 r
Creating the right environment for results paid off well for OUC in 2003. We made a strong showing, both operationally and financially. We exceeded our net income projections, kept expenses down, improved efficiencies across the company and positioned ourselves well for continued success.
At the same time, we made strides in advantageous new directions with 0 UCoolingand OUConvenient Lighting. Our hard-earned reputation as The Reliable One really helped open doors - very big doors - for these chilled water and commercial lighting divisions. One of our newest OUCoolingcustomers, in fact, is the Phase V expansion of the Orange County Convention Center. OUC provides the nation's second-largest convention center with more than 16,000 tons of chilled water capacity.
OUC laid the groundwork many years ago for a chilled water district at the Convention Center site and is actively working to add customers to our system in the future. Our downtown Orlando chilled water loop is expanding rapidly, too, spurred by the addition of numerous new high-rise projects.
OUConvenient Lighting really took off in 2003 as OUC secured contracts with large residential and commercial properties in Orlando as well as major projects outside our traditional service territory, such as Reunion Resort & Club in Osceola County. Not
! only do developers like how easy the lights are to install and maintain, communities like Baldwin Park and Harmony want an
_V'Attractive, unique product. As a result, our lighting product line includes some of the most attractive residential streetlights available, and the reaction from developers has been incredible.
Most important of all, we were able to maintain the high level of reliable service our customers expect. Our new
- k ig 633-megawatt Stanton A combined-cycle unit went commercial in the fall, on time and under budget. The new j iplant is owned in partnership with the Southern Company. It incorporates the most environmentally advanced
&iWI technology available and enables us to diversify our fuel mix while adding more flexibility to our generation 7 ?jfortfolio of owned and purchased power.
A Perhaps our proudest moment was being named the most reliable electric utility in the southeastern United States for the second year in a row. The award, given by PA Consulting Group, recognizes utilities for their
' t superior service, restoration and responsiveness records. This award was a result of us building reliability into our system from design and maintenance standpoints and reflects the high level of commitment OUC places t on providing a superior level of service to our customers.
.< unfavorable weather and the state's overabundant wholesale power supply. We did this without raising rates for either electric or water customers. In fact, our rates are among the lowest in the state. That's a pretty good elhen you consider that we provide the state's highest level of reliability as well as great-tasting drinking water treated with a state-of-the-art ozone process.
In 2004, we see many opportunities for growth in both our Orlando and St. Cloud service territories.
ur efforts will be geared toward providing the infrastructure necessary to facilitate our expanding
- y -customer base while offering the innovative products and services needed to ensure smart, efficient growth. On top of that, we plan to kick off a "green pricing" program that will allow our customers to
-' invest in renewable energy resources.
IWe're doing all of this, in addition to watching expenses and maintaining our reputation as
'-The Reliable One. Now that's creating the right environment for results.
4-'-
w- I - N Tico Perez, Esq. Robert C. Haven, P.E.
Commission President General Alanager and Chief Executive Officer ANNUAL REPORT 2003 Z
' F>1-' :
Th - .owntown D:;: Enviro iEt UCoolingunderwent he lead d another peniod of Sqa-Bh of Am~erica
- :feverish construction - Communit andd epansion l Corporatio;chosetooutsourc dwtwOrando, ouir "'distric t-he~produ ction of chilled water coolinig"division nowprovides air-,"';to'OUCo61i ingbecauseianted conitonngseVice to more than 7 ~amore economical tobefe k h *- '1 a dozen large commercial 'y tng ci led watie custonmefrs representing 2 mPlion'2 Ifroni u"; th'developer avoid e square feet of space combined the' p t ital costs With inew-hih-rises breakiig 'assoitdwt uying its own
- .ground alImost monthly, chillers Ontoofth~atthe 0 0 o UCooling'staff are m'eeitingz
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eveloper does aetow ry rgularly wtdevelopers to abouanchlerltd dem"onst rate the fin~ancial and oeain n aneac operational benefits of off-site noisyA/C units.
cooling systems. Byt eend of fis 2003 These
-We re particularly pruofhhowl ,:OUoolinghad many othernew additional OUCooltngplayedakey roe in clnts ready to it intotthi customers aredrivi re-energizing downitowns west innovative cooling solution Th development ofa
.side,a traditionally low-incomeSanctuary Downto ff Lake. Chiller Plantin downto urban community.We extended _-. Eola and the'Eola Park Place Orlando which eventually will "
'our chiled water lines to the - fmly the Four. Points
-rmuch-anticipated Hughes Square Sheraton) have signed agreements, -. ,South Plant.
pro)ect, which includes'the while ridaAM ersy 50,000square-footHughes-: 'newiSchool ofLaw,the OUCoolingbroughtonliea :
Supply Inc. headquarters, 25,000 .... condominiums at 55 West and a mammoth 17.6 -mllion gallon square feet of retail space and the new ice tower are aclose chiled w tk he lar O
266-unitCity R'A U ewapartmetnts.
2 03' to committing to OUCooling su ta wEPOr j ANNUAL REPeO~RTu t:t 09: y<r ij 0t
Olier onegof th firs tenantsa th .e v SsiF discusses eneryefcec vt ag SCiy V.,is W t,,,
,o newly expanded Oranei County -cool a~4 dcnf)7onr ocnrt ntercr Convention Center. Working in in U~oolng'scompetencies of buildigolesn Akeyfacto tandem with'20 water chillers, this: explosive gowth has been the trend saecm nies like OUC-ooling
'tank feeds a cooling loop that can toward s the have taken over the costly and o:ften handle more than 33,000 gallons' of economy hs ti ed, building. timeconsuming task of providin 38-degree water each minute, . owne'rs h;ave explored innovative sevcssuch a's chilled water.
keeping conventioneers and a avenuesfi saving capi al and nearby Lockheed Martin facility improving profits-. While these ANNUAL REPORT 2003
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___ -__ IN O UConvenient Lighting Installing a few thousand new In a separate pushed into uncharted lights each year really adds up, initiative to improve-territory last year, with each light affording long- efficiencies, our.
signing up a slate of new high- term maintenance revenues. And OUCustomer Con profile customers and installing these revenues are sure to expand completed the first h more than 2,500 lights overall. as OUC continues to sign of a two-year pro We entered into lighting contracts to install and maintain aimed at bringing more-agreements with several notable lighting in areas outside our than 25,000 apartment ad residential communities, traditional service territory. condominium meters onto' including Baldwin Park in Meanwhile, the number of an automated meter-redn &
Orlando, Harmony in Osceola customers seeking our indoor system. This so-called
- I 17, County and Reunion Resort & lighting expertise has grown "micronet" system allows I I :11 II
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.. - I I I Club near Walt Disney World. tremendously, too. OUC to take meter readings and At the same time, we negotiated OUConvenient Lighting perform service turn-ons and I I
new lighting contracts with continued to work closely with turn-offs without sending I shopping centers, office commercial customers to retrofit personnel into the field. Not only i buildings, sports facilities and their indoor lighting last year. By does this system save us money, i I
Ii other commercial customers. replacing older incandescent it generates 100 percent accurate II II Our commercial lighting lighting with cooler, more readings and delivers a wealth of I I
division - an increasingly energy-efficient fluorescent historical account information to I competitive part of our business- lighting, customers can decrease the desktops of our customer represents a strong revenue- energy usage and realize service representatives.
generating opportunity for OUC. significant savings. Also last year, a new interactive ANNUAL REPORT 2003
voice-response system helped improvements we made last year the changes: a new Developers our customer service team to the way. we work with Handbook that better guides effectively manage a sizable jump developerIs. Inyears past, our how builders, contractors and in incoming calls. Our average -Developmient Services division property owners interface with monthly call volume, in fact, spent much of its time. the utility during the reached more than'35,000. concentrating on day-to-day development cycle.
Meanwhile, an improved system operations.But a renewed focus Across our entire of managing collections helped on service in 2003 gave the OUCustomer Connection, we're us slash bad debt expense by -division a proactive set of tools focused on becoming more more than 25 percent. and guidelines for improving the competitive -and helping We are particularly proud of development experience. Among customers do the same.
ANNUAL REPORT 2003 S
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ringing a new generating unit online last year meant ensuring a more efficiently than earlier
technologies.,
Stanton A comes on the heels tight'margins.,
As utilities across Florida have continued supply of' .of two other key pieces of our installed new competitively priced electricity asset-restructuring plan: the: capacity to boost for our customers, well into the sale of our oldest generating- reserve margins future. It also marked the assets, the Indian River steam from 15 to 20
.o 1 successful completion of a units, in 1999 and-the formal percent, competition: . 1, three-part asset-restructuring institution of an Energy RiskE for short-term sales has plan in our Power Resources. Management Program a year. increased. To perform-.-'.
Business Unit. later. This latter'program saved effectively in this environment, a-Developed in partnership with our customers $2 million in we have adopted a more Southern Company, the 633- 'fiscal 2003. aggressive management style.
megawatt Stanton Unit A Combined with funding from While we might be tempted features the most our fuel-stabilization account, to sit back and savor the success environmentally advanced our risk management strategies of our restructuring efforts, the technology available. The unit helped us hold the line on retail reality of serving a growing includes two natural gas-fired electric rates last year while the customer base leaves little combustion turbines, two' state's major utilities passed opportunity to relax. New heat-recovery steam generators along increases. generation will be needed again and a steam turbine. This Meanwhile, the speculative by 2008, so we are already CCcombined-cycle" configuration wholesale power market of just a moving into our next phase minimizes emissions and few years ago has given way to a of planning. At the same time, generates electricity 30 percent period of fewer transactionsb and we are continuing to modernize ANNUAL REPORT 2003
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edn whidiistunepds to. ,s rating, such bbofeetasomr n nionetlta lowe inuacecssardM le lgfil~i- tures1 tyicall thes ou dASl~mh dfa+nea
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-security measures were, -; scfav, deii.- , ewr e~dal vehcewil imfplemented fin 2003, includin Ai-hrdivisin Huaeuing mainteniance costs'and-.
enhAe isorisin-dteionmade sure OU mrJgsft tAechnology at al U ae ainitainedlIts status as ieof Oto fta, Corporate---
pasugaegaeafour C-lnfralF16ridas most"faiiiily- Services' save( ~more-than$
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'Aedj'dipne 'ml lo ii6 therpstoyer digitl~ideseill~eis~ems dvisions many, successes last yeartrt~isdvt ae atorfclte. 'wscoxiducting asreoF-. osting initiativ securityr worikshops' arsmna ANUL REPORT 200
77 i F, l nnviro 7 '7 7J77-~~7'"'7 -7 777'7 4.- .. '.T,
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E0nvirnment W Then you operate a locally owned electric and water utility, responsibility is of paramount importance. At OUC, our v board members are focused on making well-informed, appropriate decisions about rates and policies - and backing up those decisions with accountability.
Known as the Commission, our governing board is made up of five citizens who live in OUC's service territory, have deep roots in our 4cosmmunity, and represent the diversity of our customer base.
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fn ' tt A ANNUAL REPORT 2003 1W
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ANNUAL REPORT 2003 0
I I A 3 3 A A (A ORLANDO UTILITIES COMMISSION Commission Members & Officers SEPTEMBER 30, 2003 AND 2002 Tico Perez, Esq.
President Tommy Boroughs, Esq.
First Vice President Lonnie C. Bell Second Vice President Katie Porta Commissioner Buddy Dyer Mayor - Commissioner Robert C. Haven, RE.
Secretary John E. Hearn Betty J. Perrow Sharon L. Knudsen Assistant Secretaries Management Robert C. Haven, RE.
General Manager and Chief Executive Officer Alvin C. Frazier TABLE OF CONTENTS Vice President Corporate Services Frederick F.Haddad, Jr.
Management's Discussion and Analysis A-2 Vice President Power Resources Business Unit Statements of Revenues, Expenses and Changes in Net Assets A-6 Roseann E. Harrington Vice President Statements of Net Assets A-7 Marketing, Communications and Community Relations Statements of Cash Flows A-9 John E. Hearn Notes to Financial Statements A-1 0 Vice President and Chief Financial Officer Independent Auditors' Report A-30 Financial Services Kenneth R Ksionek Vice President Energy Delivery Business Unit Douglas M. Spencer Vice President OUCustomer Connection Thomas B. Tart, Esq.
Vice President and General Counsel Thomas E. Washburn Vice President Transmission Business Unit and Chief Information Officer Prepared by Accounting Services
,M ANNUAL REPORT 2003
A Abe i/ 3 -_91 A-f,
£ 0 AI This discussion should be read in conjunction with the'Financial Statements and Notes to the Financial Statements.
Management's!Report -
The management of Orlando Utilities Commission'(OUC) has prepared -and isresponsible for -the integrity and objectivity of the financial statements and related information included in this report. The financial statements have been prepared in' accordance with generally accepted accounting principles and follow the standards outlined by the Governmental Accounting Standards Board.
To ensure the integrity of our financial statements, OUC maintains'a system of internal accounting controls. These internal -
-accounting controls are supported by written'policies and procedures and an organizational structure that appropriately assigns responsibilities to mitigate risks. These controls have been put inplace to ensure OUC's assets are properly safeguarded and the :
books and records reflect only those transactions that have been duly authorized. OUC's controls are evaluated on an ongoing.
basis by both management and OUC's internal auditors. Inaddition, Deloitte & Touche; LLP, OUCs independent public-accountants, consider certain elements of the internal control systemeto determine their auditing procedures for the purpose of expressing anopinion on the financial statements.
Based on the statements above, it is management's assertion that the financial statements do-not omit or improperly include '
untrue statements of a material fact or include statements of a misleading' nature.
- :- S ,-
/V:d 4 VkcIA9; Robert C.Haven, PE. John E. Hearn- Mindy E Willis General Manager and Vce President and: Director V
a Chief Executive Officer -Chief Financial Officer Accounting Services -
7' 7-4-
-ANNUAL REPORT 20036N
Overview of the Financial Statements This discussion and analysis is intended to serve as an introduction to OUC's financial statements. It defines the basic financial statements and summarizes OUC's general financial condition and result of operations.
Basic Financial Statements The basic financial statements are prepared to provide the reader with a comprehensive overview of OUC's statement of position and operations.
The Statements of Net Assets, previously titled Balance Sheet, presents information on all of OUC's assets and liabilities with the difference between these two amounts being reported as net assets. OUC's assets are separated for reporting purposes based on their nature. Utility plant includes those assets which are both in service and those currently under construction. Restricted and designated assets include cash and cash equivalents either legally or internally restricted by debt covenants, charter requirements or Commission action. Current assets, other assets and liabilities are reported based on their liquidity.
The Statements of Revenues, Expenses and Changes in Net Assets present both current and prior year revenues and expenses. Operating results are reported separately from non-operating and contributions in aid of construction activities. Non-operating income and expense are primarily the result of current and prior year financing and investing activities. Contributions in aid of construction typically are comprised of amounts received from residential and commercial customers for system enhancements.
The Statements of Cash Flows are presented using the direct method. This method outlines the sources and uses of cash as it relates to operating income. In addition, included in the Cash Flows Statement are classifications for non-capital related financing, capital related financing, and investing activities.
Financial Highlights Summary of Financial Position and Changes inNet Assets Year Ended September 30 (Dollars in thousands) 2003 2002 Assets Utility plant - net $ 1,704,987 $ 1,606,748 Restricted assets 545,166 568,778 Current assets 211,379 198,852 Noncurrent assets and deferred charges 24,717 24,849 S 2,486,249 $ 2,399,227 Liabilities and net assets Long-term debt - net $ 1,260,061 $ 1,281,333 Restricted & unrestricted current liabilities 247,644 210,087 Other liabilities and deferred charges 288,403 250,040 Net assets Invested incapital assets, net or related debt 454,637 432,324 Restricted 51,665 51,289 Unrestricted 183,839 174,154
$ 2,486,249 $ 2,399,227 Revenues, expenses and changes in net assets Operating revenues $ 559,713 $ 495,741 Operating expenses 443,007 406,215 Operating income 116,706 89,526 Net non-operating expense (61,689) (42,501)
Income before contributions 55,017 47,025 Contributions in aid of construction 10,348 10,916 Annual dividend payments (32,991) (28,200)
Increase in net assets 32,374 29,741 Net assets - beginning of year 657,767 628,026 Net assets - end of year $ 690,141 $ 657,767 ANNUAL REPORT 2003
Reporting Changes &Significant Accounting Policies In 2003, OUC implemented Statement of Governmental Accounting Standards (SGAS) No. 38, Certain Financial Statement Note Disclosures, an amendment to SGAS No. 34 and SGAS No.137, Basic Financial Statements -and Management's Discussion and: -
Analysis - for State and Local Governments: Omnibus.'The implementation of this statement, although not affecting OUC's financial position or results of operations, did result in reporting presentation changes.
Also in 2003, OUC adopted Federal Energy Regulatory Commission (FERC) Order 631, Accounting for Asset Retirement Obligations (ARO).
The implementation of this order affected the manner in which OUC'recorded and reported its legal obligation related to tangible long-lived assets. As a result of this order, OUC reclassified accumulated depreciation on nuclear generation facilities (long-lived assets for which OUC has a legal obligation) to anasset retirement obligation account under th' heading of Asset Retirement Obligation and Other Liabilities in the Statement of Net Assets. In addition, this obligation was adjusted to its current year net present value retirement obligation through'the recording of a fair value asset. The recording of this fair value asset did affect OUC's financial position by increasing the value of utility plant by $16 million with the offset being recorded to the asset retirement obligation liability. The'fair'value assets will be depreciated over the license period of each nuclear generation facility. Operations were not impacted as a result of implementing FERC Order 631.
Lastly, OUC adopted the Governmental Accounting Standards Board's Technical Bulletin No. 2003-01,' Disclosure Requirements for Derivatives Not Presented at Fair Value on the Statement of Net Assets.-.The adoption'of this guidance did not affect OUC's financial position or results of operations. However, it did result in reporting presentation changes that were incorporated into the footnote disclosures for long-term debt and commitment and contingencies.
Utility Plant At the close of 2003, the 633-megawatt combined-cycle plant (SECA) that was being constructed by Southern Company on OUC's Stanton Energy Center site in 2002 was completed. OUC retains a 28% '/ownership interest in this plant with the remaining ownership interests being retained by Southern Company (65%) and other Florida municipal electric utilities Q7%). In addition, through purchased power agreements executed for a minimum of'10 years,' OUC and the 'other Florida municipal electric utilities will have the rights to purchase the generation output of S6uthern Company's ownership interest'at their proportionate interest shares:
52% and 13%, respectively. Total generation facility construction costs for OUC as of September 30, 2003 are $72.6 million.
In conjunction with SECA, OUC is constructing additional shared facilities induding a brin6plant and water interconnect facilities. These assets are still under construction and will be owned by the Stanton Unit 1 & 2 participants, in their existing ownership interest percentages.
As a result of adopting FERC Order 631,' OUC created fair value assets in'the amount of $16 million that will be depreciated over the license period of each nuclear plant. Offsetting liabilities were recorded with these new assets and are included in the Asset Retirement Obligation and Other Liabilities classification of the Statement of Net Assets.'
Water plant assets increased $15 million in 2003 as compared to 2002as a result of the construction of the Sky Lake water treatment plant. This plant is scheduled to come on-line in December 2003. '
OUC's Chilled Water division with assets classified under the heading of common plant,'continue to grow as a result of expansion of the International Drive operating loop.
Long-Term -Debt The continuing low interest rate environment in 2003 cretted several refunding aid financing opportunities. OUC refunded outstanding bonds totaling$365.6 million. These refunding transactions yielded net present value savings of approximately $24.5 million. In addition, in November 2002, OUC issued variable rate debt in the amnount of $100 million to provide funds for capital projects.
Subsequent to year end, OUC issued $55.3 million' 'of fixed rate taxable bonds (Series 2003T) to fund a portion of OUC's unfunded accrued actuarial pension liability. With the issuance of these bonds in November2003, OUC's new general bond resolution became effective. In addition, credit ratings on'all senior lien bonds where confirmed'and junior lien bonds were upgraded. Credit'ratings as of the issuance of the Series 2003T are:
SUMMARY
OF OUC'S BOND RATINGS Fitch Investors Service"'- AA Moody's Investors Serv'ice Aal Standard & Poor's - AA aANNUAL REPORT 2003
Results of Operations OUC's income before contributions increased $8 million or 17% in 2003 as compared to 2002. The increase in income before contributions from $47 million in 2002 to $55 million in 2003 was the result of the strengthening of the Central Florida economy and the continued expansion of new services such as chilled water and streetlights.
Retail revenue in 2003 increased $43.4 million from 2002. The increase isdue to the recovery of rising fuel and purchased power costs, and growth inthe retail customer base. Resale revenue in 2003 increased $11.3 million from 2002 also due to rising fuel and purchased power costs.
Water revenue in 2003 was $46.3 million as compared to $41.9 million in 2002. This increase isthe result of an overall 10% rate increase effective October 1, 2002, the implementation of conservation rates for commercial customers and an increase inthe customer base -
all of which were offset by a decrease in consumption. Consumption decreased due to continued conservation efforts and rainfall that was 16 inches or 33% above normal.
Other revenues increased $4.9 million in 2003. This increase isconsistent with the increase experienced in 2002 and continues to be attributable to the planned expansion in the chilled water and streetlight operating segments. Chilled water revenues increased as new operating plant loops at the Mall at Millenia and the Orange County Convention Center expanded. Streetlight revenues also increased as OUC expanded services in the Central Florida area.
The following charts compare revenue by customer source:
September 30, 2003 September 30, 2002 Service Fees Service Fees 4% 3%
Costs related to fuel for generation and purchased power increased $31.2 million, or 16%, in 2003 compared to 2002. A large portion of this increase is the result of volatile gas and oil prices. In addition, OUC acquired more purchased power to accommodate the increase in customer base load requirements and as such costs in 2003 increased as compared to 2002. The ability to utilize established purchased power agreements to meet a portion of demand ispart of OUC's continued generation strategy.
Unit/department expenses were $6.9 million higher in 2003 compared to 2002 as a result of increased plant maintenance and labor costs.
Depreciation and amortization decreased as a result of the governing board's action to discontinue accelerating depreciation on the St. Lucie Unit 2 nuclear generation facility. Additional depreciation of $7.2 million was recorded in 2002 compared to $0 in 2003.
Total net non-operating expense was $61.7 million in 2003 as compared to $42.5 million in 2002. This change isa result of the following factors:
- Lower interest rates on investments. in addition, $56.6 million of previously restricted debt service reserve funds have been used to refund higher interest rates bonds and were not available for investment.
- In 2002, OUC executed land and land rights sales of $2.8 million. There were no comparable sales in 2003.
- OUC's governing board determined to defer the amortization of a portion of the gain on sale of assets until 2004. No gain was recognized in 2003 as compared to $13.4 million recognized in2002.
- Lower interest rates on refunded bonds and outstanding variable rate debt in 2003 as compared to 2002.
Revenues from contributions in aid of construction for 2003 are consistent with 2002. The annual dividend for 2003 increased consistent with income before contributions.
ANNUAL REPORT 2003
A S ~ A
'. Year Ended Septembi&r30 I Revenues, Expenses &Net Assets (Dollasin thousands :2003 . :2002 Operating revenues:
Retail electric revenue, net $ 364,328 $ 320,932 Resale electric revenue, net ; 128,329 .117,063 Water revenues, net 41,854 Other revenues 207215,892 Total operating revenues 559,713 495,741 operating expenses:
Fuel for generation and purchased power 221,193 189,967 Unit/department expenses 118,549 111,595 Depreciation and amortization 70,747 74,157 Payments to other governments and taxes 32,518 30,496 Total operating expenses ~443,007 406,215 Operating income 116,706 89,526 Non-operating income and expense:
Interest income 10,611 14,658 Other income, net 2,295 4,848 Amortization of deferred gain on sale of assets -13,433 Interest expense (74,595) (75,440)
- Total net non-operating expense '(61,689) (42,501)'
income before contributions 55,017 47,025 Revenue from contributions in aid of construction 10,348 10,916 Annual dividend payment (32,991). (28,200)
Increase innet assets 32,374 29,741 Net assets - beginning of year 657,767 628,026 Net assets - end of year $ 690,141 $ 657,767 See notes to the financial statements.
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ANNUAL REPORT 20~
A- --- -
Year Ended September 30 Assets (Dollars in thousands) 2003 2002 Utility plant Electric $ 1,872,848 $ 1,725,152 Water 373,659 362,632 Common 148,789 135,266 Allowances for depreciation and amortization (795,645) (748,094) 1,599,651 1,474,956 Land and other non-depreciable assets 29,267 28,652 Construction work in oroaress 76,069 103,140 Utility plant, net 1,704,987 1,606,748 Restricted and internally designated assets Debt service and related funds 101,718 164,883 Construction and related funds 87,212 46,522 Renewal and replacement fund 48,954 48,939 Customer meter deposits 21,141 19,161 Total restricted assets 259,025 279,505 Liability reduction fund 191,382 189,122 Stabilization funds 89,279 95,392 Self-insurance fund 5,480 4,759 Total internally designated assets 286,141 289,273 Total restricted and internally designated assets 545,166 568,778 Current assets Cash and investments 72,633 55,324 Customer accounts receivable, less allowance for doubtful accounts (2003 - $ 959, 2002 - $1,388) 60,960 59,225 Accrued utility revenue 26,330 26,126 Fuel for generation 9,105 10,404 Materials and supplies inventory 26,852 28,567 Accrued interest receivable 2,286 2,082 Miscellaneous receivables and prepaid expenses 13,213 17,124 Total current assets 211,379 198,852 Other assets Deferred charges 19,047 19,872 Unamortized debt issuance costs 3,177 2,693 Other deferred costs 2,493 _ 2,284 Total other assets 24,717 24,849 Total assets $ 2,486,249 $ 2,399,227 See notes to the financial statements.
3G ANNUAL REPORT 2003
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'Year Ended September 30 Liabilities '(Dollars inthousands) ~..;~2003 2002 Current liabilities Payable from restricted assets Accrued interest payable on notes and bonds $ 26,567 1$ 31,048 .
Current portion oflong-term debt :~129,250 91,155 Customer meter deposits 21,141. 7 19,161 Total payable from restricted assets 176,958 141,364' Payable from current assets Accounts payable and accrued expensds 54,1 47 '57,130 Billings on behalf of state and local governments - 10,039, 9,653 Accrued payments to the City of Orlando 5,503 1,650 Accrued swvap payables 997 290 Total payable from current assets 70,686 -68,723:
Total current liabilities 2~47,64 2110,087~~~
Other liabilities and deferred credits Deferred gain on sale of assets 1,09 110,000 Deerdrevenue 134,170 138,783, Asset retirement obligation and other liabilitie's 43,224 1,257 Total other liabilities and deferred credits 288,403 250,040 Long-term debt' Bond and note prncipal 1,329,105 :1,373,780
-Unamortized discount and deferred amount on refunding (6,4)(92,447)
Total long-term debt, net 1,20611281,333 Total liabilities $ 1,796,108 $ 1,741A.60, Net Assets Invested inc~apital assets, net of reae et$ -4467$ 432,324 Restricted 51,665 51,289 Unrestricted ".183,839 174,154 Total net as-sets $ 69014 $ 657,767 See notes to the financial statements. -
m " ANNUAL REPORT7:20030
I I
_ 5ilam Year Ended September 30 (Dollars in thousands) 2003 2002 Cash flows from operating activities Cash received from customers $ 555,745 $ 507,020 Cash paid for fuel and purchased power (214,226) (192,805)
Cash paid for unit/department expenses (123,476) (110,237)
Cash paid for other payments and taxes (32,468) (31,506)
Net cash provided by operating activities 185,575 172,472 Cash flows from non-capital related financing activities Annual divident payment (29,156) (35,091)
Net cash used in non-capital related financing activities (29,156) (35,091)
Cash flows from capital related financing activities Debt interest payments (71,647) (74,483)
Principal payments on long-term debt (459,569) (432,089)
Debt issuances 472,697 394,813 Debt issue expenses (4,261) (19,266)
Construction and acquisition of utility plant net of contributions (119,300) (145,149)
Net cash used in capital related financing activities (182,080) (276,174)
Cash flows from investing activities Proceeds from sales and maturities of investment securities 584,420 476,076 Proceeds for gain on sale of investments 1,418 2,488 Purchases of investment securities (610,284) (312,354)
Investment and other income 17,982 34,526 Net cash (used)/provided by investing activities (6A64) 200,736 Net (decrease)/increase in cash and cash equivalents (32,125) 61,943 Balance - beginning of year 220,979 159,036 Balance - end of year $ 188,854 $ 220,979 Reconciliation of operating income to net cash provided by operating activities Operating income $ 116,706 $ 89,526 Adjustments to reconcile operating income to net cash provided by operating activities Depreciation and amortization charged to operations 70,747 74,157 Depreciation and amortization charged to fuel for generation and purchased power 2,083 1,941 Depreciation of vehicles and equipment charged to unit/department expenses 3,140 1,902 Changes inassets and liabilities Decrease/(lncrease) in receivables and accrued revenue 3,103 (2,890)
Decreasel(lncrease) in fuel and materials and supplies inventories 2,598 (7,979)
Increase in accounts payable 1,942 2,166 (Decrease)Ancrease in deposits payable and deferred items (2,977) 247 (Decrease)Ancrease in stabilization and deferred revenue (11,767) 13,402 Net cash provided by operating activities $ 185,575 $ 172,472 Reconciliation of cash and cash equivalents Internally designated investments $ 124,523 $ 159,823 Cash and investments 29,061 29,311 Construction and related funds 19,759 22,598 Debt service and related funds 15,511 9,247 Cash and cash equivalents at the end of the year $ 188,854 $ 220,979 See notes to the financial statements.
ANNUAL REPORT 2003
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Recent accounting pronouncements: As an adjunct to the implementation of Statement of Governmental Accounting Standards (SGAS) No. 34 in 2002, OUC has implemented SGAS 38, Certain Financial Statement Note Disclosures. Included in this pronouncement are reporting changes to the debt footnote and the segregation of material receivables and payables. The required changes have no financial impact to OUC's financial statements.
Note B - Summary of Significant Accounting Policies (continued)
In January 2003 OUC adopted Federal Energy Regulatory Commission (FERC) document RM02-7-000, Order 631, Accounting for Asset Retirement Obligations (ARO). This order requires the recognition of the net present value of the legal financial requirement related to the dismantlement, restoration and retirement of tangible long-lived assets. The implementation of this order resulted in the recording of a fair value asset for the differential of the net present value retirement obligation of OUC's interest inthe St. Lucie Unit 2 and Crystal River Unit 3 nuclear generation facilities and the existing amount of accrued retirement obligation, previously recorded as allowance for decommissioning.
Fair value assets of $12.3 million and $3.7 million for St Lucie 2 and Crystal River 3, respectively, were recorded under the heading of Utility plant in the Statement of Net Assets effective October 1, 2002 and will be depreciated over the remaining approved license periods (see Note C). The accrued retirement obligation will be accreted over the same period based on the approved earnings rate, and both costs will be recorded as depreciation expense in the Statement of Revenues, Expenses and Changes in Net Assets (see additional information under the heading of Asset retirement obligation and other liabilities in this Note). As a result of implementing this FERC order, there was no impact to the results of operations.
In June 2003, the Governmental Accounting Standards Board issued Technical Bulletin No. 2003-1, Disclosure Requirements for Derivatives Not Presented at Fair Value on the Statement of Net Assets. This guidance addresses the disclosure requirements for derivative instruments not reported at fair value on the Statement of Net Assets including providing information related to the significance of the outstanding derivatives and their associated risks. Derivative instruments are used by OUC in conjunction with debt financing and fuel purchases.
Financing related derivative information is included under the heading of Interest Rate Swaps in Note H.Fuel related derivative information is included in Note I.
Utility plant Utility plant isstated at historical cost with the exception of the fair value asset recorded as a result of OUC's implementation of FERC Order 631 in 2003. Historic utility plant costs include the costs of contract work, labor, materials and allocated indirect charges for equipment, supervision and engineering. The fair value asset, recorded in 2003, will be re-measured every five years as required by the FPSC for nuclear generation facilities. All assets are depreciated systematically using the straight-line method over the estimated useful life or license period of the asset. OUC charges the cost of repairs and minor replacements to maintenance expense. The cost of electric or water utility plant assets retired, together with removal costs less salvage, are charged to accumulated depreciation; however, when utility plant constituting an operating unit or system is sold or disposed of, the gain or loss on the sale or disposal isrecorded as a gain (loss) on disposition of property unless regulatory action istaken by the governing board.
Cash, cash equivalents & investments: Cash equivalents include all authorized instruments purchased with an original maturity date of three months or less including all investments in the Surplus Funds Investment Pool Trust Fund and money market funds. These instruments and the money market funds are reported at amortized cost, and the Florida Local Government Surplus Funds Trust Fund (SBA), an external 2a-7 investment pool, ispresented at the share price.
Investments are reported at fair market value with the exception of the funds held inthe Debt Service Reserve funds. The Debt Service Reserve funds, in accordance with OUC's ratemaking model and their intention to retain these investments until the related debt instruments have reached maturity or the series has been refunded, are recorded at amortized cost. As a result of refunding activity in 2003, the amount of funds retained in the Debt Service Reserve funds have decreased significantly and as such, the fair market value of these investments at September 30, 2003 have decreased to $60,000 in excess of amortized cost as compared to $5.6 million in September 30, 2002. Realized and unrealized gains and losses for all investments except those executed in conjunction with a bond refunding are included in interest income on the Statements of Revenues, Expenses and Changes in Net Assets. Realized gains recognized as a result of bond refundings are included as a reduction of unamortized loss on refunding. Premiums and discounts on bonds and other investments are amortized using the effective interest method.
- s ANNUAL REPORT 2003
Note B u mayo igiiat Accoutn oiie cniud Derivative instruments: Fuel related derivative transactio' are executed in acordne wtOUsinenall salse Energy Risk Management Oversight Comnmittee'(Commrittee) whose primary.objective isto minimz xouetoergpicvltiyfocahlw ado'toprpss TeCm-mittee has a defined organizati~a tucuradrepniltes whch inc ude aproving all brokerage
- relationships, counter-pairty credit worthiness, and overall programncompliance.-In addition, the Energy Rik'Mngmn Pogaws established with specif icvolume arid financial limnits, which are 20% of th'e annual fuel bbdget arid $30 million of the gross current rmarket valu of the derivatives. Tihe' recor-ding -of fuel deriv~at~iv'es,:wh'e'n ap:p~rop:riate, isincluded on the Statements of Net Assets as either an asset or-
- liabilitymeasured at fair imarket value.:Related gain's anid/or l6s~s rae- dAfied- nd r~cognized fin'the speiefic period in which the derivative is settle n nldd pr fFe o genertio aduhsd power costs inthe Statements of Revenues, Expenses and Changes in Net Assbts.
Financial related derivative transactions and interest rate swpareet re executed to modify interest rates on outstanding debt.
Periodic'ally, as defined by the underlying a'reenientr thentdfrnta between the fixecl andvariable rates i'sexchanged with'the counter part and included as part of interest expense costs. Nfimrktvleaonseledotheageements are recorded on the
- Staterrent of Net Assets. Fair value amounts of these financial ntuet r nlddi Not H.
Accounts receivables and accrued unbille revenue: OUC bills customers monthyo acylalbssadacesrvnsathendo-the fiscil year for el1ectri and water consumed but not billed (see Ratesi aind Revenues" sec-tion above).:The customer net accounts,
-receivable balance of $60.9 millio'n'and $59.2 mlin at September 30 "2003 and 2002,riespeively,' includes billings on behalf of state and' other local governments, less administrative expenses of $10 million and $9.6 million, respectively>.
Miscellneou reeivables include billings to power plant -pariciat o hirprtionate share of fuel, operating and 'capital costs.4~
At'Septem b& 30,' 2003 arid 2002, receivables fr' m these participat ae$.milo rd11 -hlinrespectively All receivables classified as current assets are anticipated to be collected within an operating cycle.
Fue~l for generation and m'aterals 'and supplie inventory: Fuel oil,'coal and materials and supplies inventories are saed at their av~era'ge cost. Nuclear fuel isincluded in utility plant andbi-mortized t6dfuel exp~ense as it isused. .,
.Unamortized debt issuance cost: Unamrfiiized 'debt issuance costs re~present io'~ts related t6 bond issuances, which are amortized ulsing th6bns itstnigmtb and recorded net bf acumul ate amodrtization.
Unamortiz-ed dis-cou-nt and deterrec amount on refundling:Unamortize'~d~isc~ount on outstanding bonds isariortized 6sing'the-b~onds
--outstanding method 'and is'recorded net of accumulated amiortization. De'ferred amountson refun'ding represent deferred losses from bond,'
rfundin These amount's are amortized over the shorter ofthe lives of -the -refunded bt 6rrfnigdb sn h taght-line metho
'and are'recorded net of accumulated amort:izatio.n
ANNUAL R EP ORT 2 003
II Note B - Summary of Significant Accounting Policies (continued)
Accounts payable and accrued expenses: Included inthis amount are vendor payables, accrued fuel costs including purchased power agreements, advance payments from power plant participants and accrued wages, sick, vaction and comp leave. The following table summarizes the significant payable balances included under this heading:
September 30 Accounts payable & accrued expenses (Dollars inthousands) 2003 2002 Fuel & purchased power payables $ 21,347 $ 15,742 Vendor payables 16,785 26,256 Accrued wages, sick, vacation and comp leave 7,945 5,488 Advance payments from power plant participants 3,930 4,001 Other accounts payable & accrued expenses 4,140 5,643 Total $ 54,147 $ 57,130 Asset retirement obligation and other liabilities: Included in this amount are the asset retirement obligations (ARO) related to the legal requirement of decommissioning OUC's interest in the St. Lucie Unit 2 and Crystal River Unit 3 nuclear generation facilities and advances from customers for construction. The asset retirement obligation was determined in 2003 based on the most recent approved FPSC report provided to OUC by the owner-operators of these plants. The amount assessed for decommissioning of these facilities, in 2000 dollars, was
$26.7 million and $8.6 million for St. Lucie Unit 2 and Crystal River Unit 3, respectively. Adjusted to 2003 dollars, based on FPSC approved earnings rates, these amounts are $31.4 million and $9.6 million, respectively.
License expirations for St. Lucie and Crystal River at September 30, 2003 and 2002 are 2023 and 2016, respectively. InOctober 2003 the FPSC approved a license extension for St. Lucie to 2043.
Contributions inaid of construction: Funds received from developers and customers for assets owned and maintained by OUC - as well as funds received for system development fees - are recorded as revenue from contributions in aid of construction in the period in which they have been received on the Statements of Revenues, Expenses and Changes in Net Assets.
Reclassifications: Certain amounts in 2002 have been reclassified to conform to the 2003 presentation.
- = ANNUAL REPORT 2003
Note C - Utility Plant Utility plant: Utility plant costs include the costs of contract work, labor, materials and allocated indirect charges for equipment, supervision and engineering'as well as the fair value assets related to thie rtirement obligations of the nuclear generation facilities beginning in'2003.
The majority of OUC's asset are self constructed and as such are accumulated tr heconstrctio capitalized to fixed assets as a transfer upon completion o f the pro ject. -:Acc-ordingly, a substantial amount of the utility plant additions are reflected as transfers:.
Activity for the years ended Septe~mber 30, 2003 an'd'Sepge`4ibe-r 30O,~2002 are as follows:
Utility pllant (net) September 30 Fai value Retirements/ September 30 (Dollars in thousands) 2002 44'Additions *!~adjustment Transfers' Redassifications 2003 Utility plant Electric (5-50 years $ 1,725,152 $ 3,539 $ 16,008 $1234 $ (65 $1,788 Water (3-50 years) 362,632 3~,660 -7,422 : (55) 373,659 Shared/customer service (3-50 years) 135,266 2,326 - 11,222 (25) 148,789 Total 'Utility plant 2,223,050 .'9,525 16,008 146,958 (245) 2,395,296 Accumulated depreciation Electric -(599,033) '(55,715) (346) (6)' 1,201 (653,954)
Water (75,097) (9,238) -159 25 (84,151),
Shared/customer service (48,582) (8,986) -(98) 120 (57,540)
Total accumulated depreciation (722,71)- (73',933) (346) -1346 (795,645)
Total depreciable utility plant, net 1,500,338 1(64,'408) 15,662 146,958 1,101 1,599,-651 Land and other non-depreciable assets 28,652 -- 624 (9) 29,267 Allowance for decommissioning (25,382) ,-2,8 Construction wvork~in progress 103,140 1 22,373 - (147,582) (1,862) 7,6 Utility plant, net $ 1,606,748 $ 57,965;:: 1,44 $ - $ (70 $174,8 Utility plant (net) September 30 Fair value Retirements! September 30 (Dol~lars inTho'u'sa'nds) 2001 Aditins adjustment Transfers' 'Re'da sifi ain' '2002'-
Utility plant Electric (5-50 years) 1,65,241 41 $ - $ '71,884 ' $ (1,383) $1,725,152 Water (3-50 years). 335,459 ' 4,046 - 23,109' ' 18 362,632 Shared/customer service (3-50 'years) 123,544 (3,808) -' 16,645' ' (,1)135,266 Total utility plant 2,109,244 -4,648 111,638 (2,480) ,2,223,050 Accumulated depreciation Electric *' (541,112 (5,7) - ' (27). - 679 ' (599,033)
Water '(67,231) 1273)
(8, - .' 42 365 (75,097)
Shared/custome~r service' (40,989) (7,866) - (5)' ' 28 (48,582)
Total accumulated depreciation ' 1' (649,332) - -(74,712) . '-13 2 (722,712)
Total depreciable utility plaint,n'net 1,5,1 7004"- 111,638 '(1,148) 1,500,338 Land and other non-dlepreciable assets -- 27,606 137 (261) 28,652 Allowance for decommissioning ' 2,4) (2,637) ,--(25,382)
Construction work in progress 71,437; 1,I42,440 - (I111,638) ~ 901, ,103,140 Utltpate>' $1,536,210 - $71,0467 :4 - $ -(508) ' $ 1,606,748
,ANNUAL'REPORT12003
I I Note D - Jointly Owned Operations OUC operated: OUC maintains fiscal, budgetary and operating control of several power generation facilities for which there are undivided participant ownership interests. These undivided ownership interests are with the Florida Municipal Power Agency (FMPA) and Kissimmee Utility Authority (KUA). Each agreement is limited to the generation facilities and excludes the external facilities. These agreements and the related ownership interests have remained consistent for the years ending September 30, 2003 and 2002 and are as follows:
Agreement Total facility net FMPA undivided KUA undivided Net OUC undivided Facility name year megawatt capacity ownership interest ownership interest ownership interest Stanton Unit 1 (SEC1) 1984 & 1985 440 26.6265% 4.8193% 68.5542%
Stanton Unit 2 (SEC2) 1991 440 28.4091% - 71.5909%
Indian River Combustion Turbines (A&B) 1988 96 39.0000% 12.2000% 48.8000%
Indian River Combustion Turbines (C&D) 1990 236 21.0000% - 79.0000%
In addition, OUC operates a wastewater treatment facility at the SEC 1 and SEC2 site through an agreement with Orange County.
Non OUC operated: OUC maintains an undivided participant interest with Florida Power & Light at their St. Lucie Unit 2 nuclear generation facility, Progress Energy at their Crystal River Unit 3 nuclear generation facility and the City of Lakeland at their McIntosh Unit 3 coal-fired generation facility. In each of these agreements, fiscal, budgetary and operational control are not maintained by OUC.
On March 19, 2001, OUC entered into an agreement with Southern Company to secure an undivided participant interest in the Stanton A combustion turbine generation facility (SECA). This generation facility is operated by Southern Company; however, as part of this agreement, for the initial 10 years of operations, OUC retains responsibility as fuel agent for the generation facility. As such, funds related to OUC's fuel agent responsibility have been restricted on the Statements of Net Assets (see Note E). At September 30, 2003 SECA was in pre-commercial operations; on October 1, 2003 commercial operations began.
These agreements and the related ownership have remained consistent for the years ending September 30, 2003 and 2002 and are as follows:
Agreement Total facility net OUC undivided Net OUC Facility name year megawatt capacity ownership interest megawatt capadty St. Lucie Unit 2 (SL2) 1980 853 6.0895% 52 McIntosh Unit 3 (MAC3) 1978 340 40.0000% 136 Crystal River Unit 3 (CR3) 1975 835 1.6015% 13 Stanton A (SECA) 2001 633 28.0000% 177 Plant balances and construction inprogress for SEC 1, SEC2, MAC3 and the Indian River Plant CTs include the cost of common and/or external facilities. At the other plants, participants pay user charges to the operating entity for the cost of common and/or external facilities. User charges paid for SECA are remitted back to OUC at their proportionate ownership interest of Shared Facilities. Allowance for depreciation and amortization of utility plant isdetermined by each participant based on their depreciation methods and rates relating to their share of the plant. During fiscal years 2003 and 2002, OUC authorized an additional $0 and $7.2 million, respectively, in depreciation of its interest in the SL2 nuclear generating facility.
- g ANNUAL REPORT 2003
Note D- Jointly Owned Operations,(continued) up.`N The following isa summary of OUC's recorded net share of each jointly power generation facility September 30 (Dollars in thousands) . 2003 2002 Stanton Energy Center Unit 1 - 180,103 i 186,149 Stanton Energy Center Unit 2 - 302,380 310,172 Stanton Energy Center Unit A 72,642 55,662 McIntosh Unit 3 58,331 60,617 St. Lucie Unit 2 45,223 34,194 Indian River Combustion Turbines 33,630 38,730 Crystal River Unit 3 - 7,179 -3,629 Allowance for decommissioning (25,382)*
Total ' 699,48 ' 663,771
- See Notes B& Cfor reclassification of allowance for decommissioning-Note E,-7 Cash, Cash Equivalents and Investmnen ts OUC's cash deposits including deposits held in an interest-bearing qualified public depository account are held in institutions insured by the Federal Deposit Insurance Corporation or collateralized by a pool of U.S. Governmental securities, per the FIorida Security of Public Deposits Ad, Chapter 280 of the Florida Statutes. In accordance with OUC's investment policy, the following types of instruments are utilized:
- Obligations which are unconditionally guaranteed by the U.S.-or its'agencies
- Repurchase and reverse repurchase agreements Money market funds
- Commercial paper S Interest-bearing qualified public depository accounts Certificates of deposit Taxable municipal bonds
- Bankers',acceptances
-d -et X P: 'b ;f - in moe are imt to
' Investments incobnercial paper nmust be rated at a minimum "A-i" & P- "UC's investments in mdrieyrnarket funds are limited to funds which meet the'Securities and Exchange Commission definition of a fund that seeks to maintain a stable net assiet value of $1 per share and is rated not less than'Aaa, AAAm or an equivalent rating by at least one nationally rec6gnized rating service.'
Investments in'repurchase agreements are secured transactions occurring between OUC and a securities dealer under a master repurchase agreement. OUC will exchange cash for temporary ownership of specified collateral with an agreed upon rate of interest ad maturity.
Specified collateral islimited to direct goviernmerptal and agency obligations with terms of 10 years and under, and held and maintained by a third party trust at a market value of 102% 'of the value of the repurchase agreement. OUC has determined the risk of default as minimal.
OUC invests funds with the Local Gov nment Surplus Funds Investment Pool Trust Fund (the "Surplus Funds Investmenit Pool"),'an investment pool administered by the State Board of Administration of Florida. included in these investments are derivative instruments, which are comprised of approximately 13.94% and 0.70i of th&e Surplus Funds Investment Pool portfolio forthe periods ended September 30, 2003 and 2002 respectively. These investments d from certain floating 'rate notes based 'on the 'prime rate and/or one and three month London Inter-bank Offered Rate rates. Investments in the Surplus Funds Investment Pool are not insured or collateralized; however, due to the stringent investment policies of these funds, OUC considers the risk of loss of principal to be remote.
' ANNUAIL REPORTL2003@.2i
II Note E- Cash, Cash Equivalents and Investments (continued)
The following are the cash, cash equivalents and investment deposits held by OUC:
September 30 (Dollars inthousands) 2003 2002 Cash $ 74,427 $ 122,710 Investments - category 1 (Insured or registered & held by OUC or agent in OUC's name)
Repurchase agreements 305 U.S. government securities 16,047 45,415 Commercial paper 69,725 Other U.S. and agency backed securities 456,679 454,710 Total investments - category 1 542,451 500,430 Total cash, cash equivalents and investments $ 616,878 S 623,140 Restricted assets Debt service and related funds:
Principal & interest funds $ 55,565 $ 61,935 Debt service reserve funds 46,153 102,948 Total debt service and related funds 101,718 164,883 Construction and related funds Nuclear generation facility decommissioning funds 29,853 27,731 Stanton A fuel 1,983 Construction funds 55,376 18,791 Total construction and related funds 87,212 46,522 Renewal & replacement fund 48,954 48,939 Customer meter deposits 21,141 19,161 Total restricted assets 259,025 279,505 Internally designated funds Liability reduction fund 191,382 189,122 Stabilization funds & customer retention 89,279 95,392 Self-insurance fund 5,480 4,759 Total internally designated funds 286,141 289,273 Other funds Cash and investments 72,633 55,324 Less accrued interest receivable from restricted assets (921) (962)
Total cash, cash equivalents and investments $ 616,878 $ 623,140 OM ANNUAL REPORT 2003
11
, - ': .i I -; 4!t tF- Regulator Deferrals N . . ' ...-
Regulatory assets: B36sed on regulatory action taken by the goverlning board,:OUC has: recorded the following regulatory assets that will be include'd in-the ratemaking' processan recovered in'future' periods, ' ...
- Deferred charges: In2002, OUC used prciceeds from the Liability:Reduction Fund (LF odfas portion, $112.2 million of the Series 1989D bonds. In conjun'ction with this defa ,teasbtdls ndfa c ($15 million) was deferred and amorie consistent with the life of the remaining outstanding Se~ries)`9'8'9D.bon~ds. In2003~, thke r-emaining Series 1989D bonds were defasd and regulatory action wa ae y te Iwstkhbtkgveri bad 66eri~ to66i6tinu&e amortizing these costs over the originial bond series life net bf the proceeds received from resrcturng the relate esrwdpsit 'trust fund. Since-the' inception of the defeasance, the proceedsfrom tcrowof the eststudeposit trus fund hvebn restructrn hvben idficent to offset period regulatory amortization costs. The outstanding.
regulatory asset at September 30, 2003 and 2002 s $13 million and $13.4 mrillion, respectively.
Deferre charges als 'include deferred interest costs on Series 1993 and 1993B bonds. These ntrscos~re incurred due to the differental be'tween'the'short-term'andl long-term rates at the,tme of bond issuance. OUC's r~eg'ula-t'ry, costs fo-r thes chagesare
.$6.1 million and $6.4 mlinat Sepeber 30 2003 and 2002, respectively. Deferred ~hargeis are' currently' amortized t'o interest' expense over the remaining period of the original bond senies' Rgulaory liabilities: Based on regulatory actions taken ,by the governing board, OUC has rec~orded the following regulatory liabilities that wil beinludd nthe ratemaking p-roces'sand reognizdd asrevenues infu~ture periods: ,:
- Deferred gain 'on sale of assets: On'October 5, 19991, OUCsold'its steam units at the Indian River Plant (IRP) and elected, to defer the gain on sl($4miion).--A portion of this deferred gain -($45 million) was designated to offset generating facility dern rid pyet
"' :a'nd truh Setebe 30 003, $34.3 milli6n has b~eWn ecognrzed In,2003 arid 2002, OUC re onzdgiso 0~d$34 million; respectively. in additioin; at the timeof the sa e OUC reeie apre-payment fothe buyer,for 20 years wbrth of transmission~
access fees,which isinclue under the heading of Deferred revenue on the Statements of Net Asets 'adi eing amortized annually ove~rthe life of the 'agreement. ,' ,~
- Deferred w~holesale-tra'ding profits: This account represents a portion of profits generated from resale sales..
.Eerianwtratstbilization- OUC's governing boarid established these 'accounts tor costs (reven-ues) tha ar6be eoee by (used to ~redu'ce) rates in'periodls other teh han' w en incurre (realizedic)-
.. Fuel stabilizatiion: This account was established in accordance with guidelines from the Public Utilities Regulatory Policies Act of 1978
- and .r~presents the difference~between the fuel costs charged to customers and the fuel costs incurred. .
.'Customerretention stabilization: This account was establsed to assist in r'etaini-ng exisiing cu-storimer-s'and attracting new customers.-
I inuac eev: OUC'sgover'ningboard established this account'tomitigatetunexpectedin~creases i'n me'dical'csst H'Healt
.employees. ..
Inconjunction with' the recording ofIeergltr oenn a has irnterna lydesinte erancashand' investments to fund ths-efras(See Note E). Eaich'of these funds ea rs the same interest rate as OUC's operating investment portfolio OUC's regulatory assets and liabi ities are as ollov~r: ~ , '
.Desrpin .Speber3 (Dollars in thousands) '.2003 .- . 2002 Deferred charges . ' 19,047 . '$ 19,872 Deferred wholesaile tr'ading-'profits $ 39,753 $ 39,232 Rate stabilization .42,519 .- 4 1.308
'Fuel stabilization 28,677" 36,565,'
Health insurance reserve' .,. 480 . .468 Cstomer retention stabilization 1581,51 8 Total regulatory liabilities included indeferred revenue 112,587. ' '1,9 Deferred gaini or sale bf assets 111,i009 - 110,000 Total regulatory liablte . 2,56 .$229,091 ANAL-RE PORT 200
I I Note G - Self-Insurance OUC's self-insurance program covers a portion of its workers' compensation, general liability and automobile liability exposures. The liability associated with this program isincluded inthe Statements of Net Assets under the caption, Accounts Payable and Accrued Expenses.
Changes to the balances of the self-insurance program liability in 2003 and 2002 are as follows:
September 30 (Dollars in thousands) 2003 2002 Balance, beginning of year $ 661 $ 353 Claims and changes in estimates 209 683 Payments of claims (390) (375)
Balance, end of year $ 480 $ 661 September 30 (Dollars in thousands) 2003 2002 Workers' compensation $ 250 250 General liability
$ 1,000 1,000 Automobile liability $ 1,000 1,000 It isthe opinion of general counsel that the Orlando Utilities Commission, as a statutory commission, may enjoy sovereign immunity in the same manner as a municipality, as allowed by Florida Court of Appeals rulings. Under said rulings, Florida Statutes limit of liability for claims or judgments by one person for general liability or auto liability is $100,000 or a total of $200,000 for the same incident or occurrence; greater liability can result only through an act of the Florida Legislature. Furthermore, any defense of sovereign immunity shall not be deemed to have been waived or the limits of liability increased as a result of obtaining or providing insurance in excess of statutory limitations. It is also the opinion of general counsel that OUC, as a municipal utility, is statutorily immune from suit for malicious prosecution.
Liability for accidents at the nuclear power plants for which OUC has a minority interest are governed by the Price Anderson Act, which limits the public liability of nuclear reactor owners for a single nuclear incident, to a combination of private insurance and retrospective assessments. Both majority owners (Florida Power & Light and Progress Energy Corporation) maintain the maximum amount of private liability insurance ($300 million) and participate in a secondary financial protection system. In addition, both majority owners participate in nuclear mutual companies that provide limited insurance coverage for property damage, decontamination and premature decommissioning risks. Irrespective of the insurance coverage, should a catastrophic loss occur at either of the plants, the amounts of insurance available may not be adequate to cover property damage and other expenses incurred. The owners of a nuclear power plant could be assessed to pay up to $101 million per unit per incident, but not more than $10 million per unit in a calendar year. Uninsured losses, to the extent not recovered through rates, would be borne by each of the owners at their proportionate ownership share and may have an adverse effect on their financial position. See Note D for OUC's ownership interest in St. Lucie Unit 2 and Crystal River Unit 3.
OUC's transmission and distribution system are not covered by property insurance, since such coverage isgenerally not available.
ANNUAL REPORT 2003
-Note H-Long-mTerm Db Activity for the years ended September, 30,:2003 and Septemnber 3,20 aea ol
'Long Term Debt Final Principial Interest Sete ber302002 Additions- Decreases Sep~tember 30. 2003- Cunrent (Dollar in thousands) ;Payment Rates ( oton Senior lie~n: i . ;. I
- 992 Bonds %,~2010 - *5.30 6.00 0/c - $25,270, $261,170 - $26,635 1993 Bonds . 2023'- 4.55. 1259 95.600 -95,600 60,0 1996A Bonds - 12023 60,000 1996B Bonds: ,201 1;". 5.10%M `:39,995-1 .39,995
- 2001 Bonds - 2023, ~3.00 - 5.250/A _258,815~ - 1,555 257,260.
-2003 Bonds .-20251 5.00% 54,775 '54,775,:,,
Toalsenior liencdebt~ 740,850:.", 54,775 . ~ 122,425 673,200 .28,370 Junior lien:,,
1989D Bonds 2023 5.00 -6.75% ,76,385 - 76,385
.1992A Bonds :2027- 5.50% -39,420 -:. 39,420
.1993A Bonds 2023. '4.90-75.50% 85,000.
1993B Bondcs 2023 ~4.75 - 5.60%/ 72,700, -. tI.-
1994A Bonds _'~2020 4.25 - 5.00%, 133,40 - 715 .132,825 745 2001 A Bonds.: :~2020 -.4.00:'5.25% 125 ~.135 2002A Bonds 2017 Variable Rate* 120,000 MM02 Bonds 2022 Variable Rate*, 100,000 :100,000 2002C Bonds 2027' 50- 5.2'5%/ ~,-70,955 70,955!
2003A Bo'nds 2022 2.50 -5.00% :118,760 118,760;;
Ir 105,700 '105,700, I *20031B Bonds 2022' 3.00- 5.00%Yc I -Total junior lien debt 5 4 0 53 , 152 , 456 5,155 8 Other debt:
1998 Bond Anticipation Notes 2003 ---3.25% 0,006 b 60,6000 1999A Bond -. ' '.
Anticipi~ation Notes ~2004 Variable Rate* 1 0 0 0. 10 0,000 i1 0,0
'Total other- debt'~ ' .. 16 0, 000 .- 60,000 '100,000 .' 100,000 Less current po6rtion :. 9 , 5 ) . 1 29,25 . - ( 11 5 . . (129,2 50) '
'Total debt - '- $1,373,780 ..- $320,940 - 365,615 4 1,329,105. $129,250
- c .*-- nr n i o.c/ 'IM 'Inn.
.V d11dUlt FIdLtz IdII1tUU IUU1iIV.0U 70 W ~ I..J /0 IUI B Ult cl~ U111UL 2D4JL~LJIL)tI DV, ILUU .
LAN NUAL REPORT-20030
Note H - Long-Term Debt (continued)
Long Term Debt Final Principal Interest September 30, 2001 Additions Decreases September 30,2002 Current (Dollars in thousands) Payment Rates (%) Portion Senior lien:
1992 Bonds 2010 5.30-6.00% $ 310,440 $ - $ 24,000 $ 286,440 $ 25,270 1993 Bonds 2023 4.75- 5.125% 139,020 - 43,420 95,600 1996A Bonds 2023 4.10% 60,000 - - 60,000 1996B Bonds 2011 5.10% 39,995 - - 39,995 2001 Bonds 2023 3.00-5.25% - 258,815 - 258,815 1,555 Total senior lien debt 549,455 258,815 67,420 740,850 26,825 Junior lien:
1989D Bonds 2023 5.00 - 6.75% 253,945 - $177,560 76,385 1991A Bonds - 5.50% 115,380 - 115,380 -
1992A Bonds 2027 5.50% 39,420 - - 39,420 1993A Bonds 2023 4.90 - 5.50% 85,425 - 425 85,000 445 1993B Bonds 2023 4.75 - 5.60% 128,435 - 55,735 72,700 3,045 1994A Bonds 2020 4.25 - 5.00% 134,225 - 685 133,540 715 2001A Bonds 2020 4.00 - 5.25% 37,040 - - 37,040 125 2002A Bonds 2017 Variable Rate* - 120,000 - 120,000 Total junior lien debt 793,870 120,000 349,785 564,085 4,330 Other debt:
Line of credit - Note 0 - 1 month LIBOR + 1.50% 25,965 4,412 30,377 -
1998 Bond Anticipation Notes 2003 3.25% 60,000 - - 60,000 60,000 1999A Bond Anticipation Notes 2004 Variable Rate* 100,000 - - 100,000 Total other debt 185,965 4,412 30,377 160,000 60,000 Less current portion (54,190) (91,155) (54,190) (91,155)
Total debt $ 1,475,100 $ 292,072 $ 393,392 $ 1,373,780 $ 91,155
- Variable rates ranged froml.05% to 2.28% for the year ended September 30, 2002.
_ ANNUAL REPORT 2003 NW
Note H-Long-Term Debt (continued)
Following isa schedule of annual prircipal and interest funding requirements'on bonds and notes outstanding at Septernber 30, 2003:
Year ending Principal ' nterest Total (Dollars inthousands) 2004 $ 133,005. 7. 64,332 - 197,337i : -
2005 :-36,435 61,683: *:98,118 2006 - 39,280 . 59,679. 98,959 2007 41,400 57,497 - 98,897 2008 43,800 55,162 :-98,962"
-2009-2013 307,640 - 230513 - 538,153 2014-2018 341,650 160,907 ; 502,557.- -
2019-2023 431,145 -. 67,852 -:498,997.-
2024-2027 : I - - -54,750 : 3.962 :
W C:
58,712
-Total: - E I.$ 1,429,105
- _ -1 $. 761,587
- $ 2,190,692 Senior lien bonds: The senior lien bonds are payable and secured by a first lien upon and pledge of the net revenues derived by OUC from:
the operation of the water and electric system and from certain investment income.
-I;~~~~~ . ,- -
0 0 ;, - ; -;,0o$A.;
- i -- ai
- !
OUC has covenanted inthe senior lien bond resolution to fix, establish and maintain rates and collect such fees, rentals or other charges for '
the services and facilities of the water and electric system, which shall be adequate at all times to pay in each fiscal year at least one hundred tvtwenty five percent (125%) of the annual debt service requirements for the bonds,'and that the 'net revenues sh'all be sufficient to make all other payments required by the terms of the senior bond resolution '- -' -
The senior bond resolution establishes the Revenue Fund Account, Renewal and Replacement Fund Account and Sinking Fund Account,'
i- - which are comprised of the Interest, Principal, Investment,; Bnd Redemption, Debt Service Reserve and Demand Charge Component - -
accounts. -
- In accordance with the senior bond resolution, gross revenues derived from the operation of the water and electric system are to be i' deposited in the Revenue Fund and shall be applied only in the following marner: -- -
- 1. ' Revenues are first to be used to pay the current operating expenses of the water and electric system and then-all Sinking Fund and -:
Renewal and Replacement Fund requirements.
- 2. The balance of any revenues remaining in the Revenue Fund shall, at the option of OUC, be used (A)for any ful p rpos i connection
' with the water and electric system and (B)to makeany payments of funds to the City of Orlando ' provided, however, that i none of the revenues is ever to be used for-the purposes described in(A) b'nd (B)unless 'allpayments required in (1)above, including any
- deficiencies for prior payments, have been made in full to the date of such use, a'nd OUC shall hav6'fully complied with all covenanrts Xand 'agreements contained in the bond resolution . 2 ' , - :. - -- -.
'bonds Junior The lienjunior lien bonds are payablefro, and secured by, a lien upon and a pledge of the net revenues derved by OUC from the
- operation of the water and electric system and certain inv'stment inicome' subjec tothe prior len theretri of OUC's'outstanding snior lienH bonds.
OUC has covenanted in the junior lien bonid res'olution'to fix,'establishand maintain such rates and collect such fees, rentals or other charges for the services and facilities provided ineach fiscal year. Net revenues derived from these'rates and fees shall be adequate, after the ; - -
Ideduction of amounts to provide and fund for the annual debt service and debt service reserve requirementsforsenior lien bonds and to
- make any required deposit to other funds and accounts established under docunments'dencing or securing senior lien bonds at all times, to
-pay ineach fiscal year the sum of at least (1)one hundred perceht (100%) of the annual debt'service requirement for the bonds issued pursuant to the resolution a'nd ariypari passu additional bonds hereafter issued for the then current fiscal year and (2)one hundred percent (100%lof the amount requiredt be deposited into the Dem'and Charge Component Account for the then current fiscal ye r; anid that such netrevenueswill be sufficient to nmake all otherpayments required by the terms of the resolution aind that such rates, fees, rentals or other charges shall not be'reduced so as to be insufficient to provide adequate revenues for such purposes. -,
A NN AL REXPRT 2 00 3
II Note H- Long-Term Debt (continued)
The junior lien bond resolution establishes the Sinking Fund that includes the Interest, Principal, Bond Redemption and Demand Charge Component Accounts. In accordance with the resolution, gross revenues are to be applied in accordance with the senior lien bond resolution and then to be applied to the Junior Lien Sinking Fund accounts.
General bond resolution: On October 9, 2001, OUC adopted a General Bond Resolution. Bonds issued after this date fall under the provisions of this new resolution. The terms of this new general bond resolution do not become effective until in excess of 51 % of OUC's outstanding Senior and Junior debt obligations have been issued under this resolution (see Note M). The most significant provisions of the new resolution are as follows:
- Rate covenant The net revenue requirement for annual debt service has been set at 100% or available funds plus net revenues at 125% of annual debt service.
- Additional bonds test This test is limited to OUC's certification that it meets rate covenant-
- Flow of funds: There are no funding requirements; however, consistent with prior resolutions, OUC can determine whether to fund a debt service reserve account on an issue-by-issue basis or internally designated funds.
- System definition: OUC's system definition has been modified to utility system. This definition is a more expansive definition to accommodate organizational changes and the expansion into new services.
- Sale of assets: System assets may be sold if the sale will not interfere with OUC's ability to meet rate covenants. Consistent with prior lien resolutions, proceeds must first be used to pay debt service.
At September 30, 2003, the Junior lien bonds, at a percentage of 75%, have reached the consent percentage; however, the Senior lien bonds at a percentage of 46% have not reached the consent percentage. Therefore, the General Bond Resolution is not effective at September 30, 2003. See Note M related to the effective date of-the General Bond Resolution.
Refunded bonds: Proceeds secured from refunding transactions are invested in United States obligations in irrevocable escrow deposit trust funds. Each escrow deposit trust isstructured to mature at such time as to provide sufficient funds for the payment of maturing principal and interest on the Refunded Bonds. All interest earned or accrued on the United States obligations has been pledged and will be used for the payment of the principal and interest on each respective bond series. As a result of a favorable rate environment, OUC has refunded $365.6 million and $276.8 million of long-term debt for fiscal years ended September 30, 2003 and 2002, respectively and are summarized below:
Debt issued Month issued Par amount Par amount PV savings Accounting loss Savings % of (Dollars in thousands) issued refunded refunded bonds 2002C Nov-02 $ 70,955 $ 84,290 $ 4,336 $ 5,473 5.14%
2003A Apr-03 118,760 .156,635 8,003 18,549 5.11%
2003B Jul-03 105,700 124,690 12,190 14,621 9.78%
$ 295,415 $ 365,615 $ 24,529 $ 38,643 Debt issued Month issued Par amount Par amount PV savings Accounting loss Savings % of (Dollars in thousands) issued refunded refunded bonds 2001 Oct-01 $ 258,815 $ 276,790 $ 19,157 $ 38,297 6.92%
Defeased bonds: InJuly 2002, OUC used proceeds from the Liability Reduction Fund (LRF) to defease $112.2 million of the Water and Electric Subordinated Revenue Bonds Series 1989D (Defeased Bonds). LRF proceeds were invested in United States obligations in an irrevocable escrow deposit trust fund and will mature at such time and in such amounts so as to provide sufficient funds for the payment of maturing principal and interest on the Defeased Bonds. The loss associated with the defeasance has been deferred ($15.5 million) and is being offset by a series of intra-day trades that are designed to recoup the loss through the restructuring of the escrow deposit trust fund on a periodic basis (see Note F).
ANNUAL REPORT 2003
Note H -Long-Term Debt (continued) frfiacareotnpupesndhvbenem edfmte All ref unded and defeaised bonds are treated as extinguished -debt irfnniareotngpuossndhvben e'm edrmte Statements of Net Assets. Defeased bonds outstanding at September 30, 2003 and 2002 are $472 million and $674 million, respectively.
Interest Rate Swaps: Interest rate swaps, a de'rivatiive financial inistruiment, are used by OUC to manage interest rate exposure on both' fixed and variable rate debt and are not executed for trading purpdsesl. Under these swap agreements, Ionly the net difference in interest calculated at fixed and Variable rates is actually exchanged with the io-untier party. The notional amounts are the basis on which interest is calculated; however, the notional amounts are not exchanged.'
Although a termination of the swap agreement may result in OUC's making or receiving a termination payment, OUC limits its execution of these agreements to major financial institutions with either high investment grade credit ratings or agreements to collateralize their net position. Therefore, OUC does not anticipate nonperformance by a counter party.
As outlined in Note B,GASB issued a technical bulletin in June 2003 requiring additional disclosure information related to derivatives.
As such, the following schedule summarizes OUC's swap agreements outstanding at September 30, 2003 with fair value amounts corresponding to the market value:
(Dollars in thousands) 2003 Notional amount ,$ 320,000 Term October 2008-2022 Rate OUC:
Received 1.94%
Paid (weighted averag~e rate),- 2.76%
Fair value liability, net $ 7,863
- The notional amounts at September 30, 2003 represent seven counhterparty agreements of which one has a call option that expires in 2009.
Note I -Commitments and Contingent Liab ilties Energy sales commitments: OUC engages in long-term resale energy contracts with several key customers for both unit specific sales, sales generated from a specific power plant, and systems sales, salesi generated from any OUC available resource. The folloing table provides a summary of OUC's power sales contracts with other companies.
unit sales System Sales Total No. of Amount of of
-No. Amount of N unt of Year contracts sales MW contracts sales MW contracts sales MW p
2004 o3 126 1 '1 05 4 'p231 2005 1 49 1113 - .162 2006 1 27' 129 2 .56 2007 6 .1 0.
Purhasd pwercomitmnts Puchaed owe comiments were executed inconjunction with the sale of the Indian River Plant steam units (see Note F)and the construction of the SECA generation fadlity. Purchased power commitments related torSECA are scheduled to begin inOctober 2003, when the plant begins commercial operations. These two agreements represent the primary purchased power commitments below Number of Amount of Year contracts megawatts 2004 3 845 2005 3 645 2006 2 345 2007 2 345 2008-2012 2 345 2013 1 330 ANNUAL REPORT 2003
I I Note I - Commitments and Contingent Liabilities (continued)
Fuel and fuel transportation commitments Coal: OUC and the other participants in SEC1 and SEC2 have entered into coal supply and rail contracts. The coal supply contracts expire in 2005 and 2006; however, each contract contains renewal and/or market price reopeners for additional years. The rail transportation contracts for the coal expire on December 31, 2007. The coal supply contracts require minimum annual purchases as follows:
Year Amount (Dollars in thousands) 2004 $ 38,769 2005 $ 39,185 2006 $ 18,163 Natural gas: OUC has entered into natural gas supply and transportation contracts. The supply contracts for SECA expire in 2004, 2005, and 2006. These contracts have an indexed-based pricing structure such that the cost of natural gas floats with market prices. Natural gas supply costs, based on current estimated market prices, are calculated below at a cost of $4.75 per MMBTU. The transportation contracts expire in 2004 and 2014 with 10-year renewal options. In addition OUC, as fuel agent for SECA, has entered into a contract effective 2004 with a minimum term of 10 years.
The following schedule summarizes natural gas transportation capacity and supply commitments at September 30, 2003:
Year Supply Capacity Total (Dollars inthousands) 2004 $59,268 $ 16,590 $ 75,858 2005 $45,516 $ 18,122 $ 63,638 2006 $36,824 $ 17,885 $ 54,709 2007 $ 17,676 $ 17,676 2008 $ 17,677 $ 17,677 2009-2014 $ 17,679 $ 17,679 Other fuel sources: OUC and the other participants have entered into a contract for the supply of 1,000,000 MMBTU's per year of methane gas for SEC1 and SEC2. The contract expires on December 31, 2007.
Derivative fuel instruments: OUC's fuel-related derivative transactions, where applicable, are recorded on the Statements of Net Assets as either an asset or liability measured at fair market value. Related gains and/or losses on these transactions are deferred and recognized in the specific period in which the instrument was settled and are included as part of the fuel and purchased power costs in the Statements of Revenues, Expenses and Changes in Net Assets. No amount is recorded for the fuel swaps other than the net monthly fuel settlement amount resulting from these agreements.
At September 30, 2003 and 2002, OUC had fuel-related derivative instruments (swaps, futures, and options) with a net fair market value of $5.6 million and $2 million, respectively. In addition, the valuation of market changes for OUC's Energy Risk Management Program contracts resulted in a decrease in fuel expenses of $2.2 million in 2003 and an increase in fuel expenses of $394,000 in 2002.
ANNUAL REPORT 2003
NoteJ- MajorAgreements-City of Orlando: OUC pays a revenue-based payment and an income-based dividend payment to the City of Orlando. The revenue-based
- payent isciassified as an operating expense and iscalculated at 6%=of gross retail electric and water billings and 4% of chilled' ater billings to customers within the City limits. The income-based dividend payment isrecorded as a reduction of net assets on-the Statements
" Revenues, Expenses and Changes in Net ssets The dividen'd iscalculated using 60% of income before contributions for all operating units except those operated under the agreernent with Trigen-Cinergy Solutions (as noted below). Dpvidends for operating units under the Trigeri-Cinrergy Solutions agreement arecalculatedbasedn i eforecontributins to $625,000 and 60% thereafter...
Dividenlds for fiscal years 2003 and 2002 totaled $33 mrillion and $28.2.million, respectively, induding accrued dividends at September 30, 2003 and 2002 of $3.8 million-and $0,respectively.i Orange County. OUC pays a revenue-based payment to Orange County calulated at 1% of gross retail electric billings to customers within the County but outside the city limits of the City of Orlando. This'payment isrecorded under'the heading of Payments and Taxes on the
. Statements of Revenues, Expenses and Changes in Net Assets City of St.' Cloud: InApril 1997, OUC entered into an interiocal agreement with the City of St. Cloud (STC) to assume responsibility for providing retail electric ehergy services to all STC ccustomers and to assume control and 'operation' of STC's electric transmission and distribution systern and certain'generation facilities. Inreturn,'OUC isobligated to pay STC 9.5% of gross retail electric billings to STC Ycutmr(amnmur of$. ilo nuly nescran event occur) and to pay STC's electric system net debt service. The term of the'-'
agreement commenced May 1,1,997 and, as amended in April 2003, coritinues until September 30, 2032. OUC's billed revenue includes '
million and $33.2 million from the interlocal agreement for the years ended September m$36.3 30, 2003 and 2002, respetively.
'Trigen-Cinergy Sou On :Juriei23, 1998, OUC entered into an agreement with Trigen-Cinergy Solutions (TCS) to construct and provide
- air conditioning cooling systems (chilled water) for buildings in the Orlando metropolitan area.'The agreement provided for interim financing in the form of a line of credit from Trigen-Cinergy (see note H)
- The lirneof credit was provided through April 4,-2002, at which time, the
- outstanding financed balance ($30.4 million) was 'reaid with- capital contributions from OUC and TCS based on the profit sharing.
percentages'of 49% and 51 %, respectively. Since this date, additional capital contributions have been'-provided for by iOUC and TCS based on their profit sharing percentage at $2.3 million and $2.9 million for the years ending September 30, 2003 and 2002, respectively TCS's contribution isnetted against utility plant to reflect its share of the future revenue streams anticipated from these assets. Total outstanding capital'contributionssfronmTCS at September 30,2003 and 2002 were $18.1 million and $16.9 million, respectively. TCS's share of totai project earnings are recorded as a liability under'the'heacing of Accounts Payable and Accrued Expenses on the Statements of Net Assets at $854,000 and $399,000 for September 30, 2003 and 2002 respectively. See Note M related to the dissolution of this agreement.
Note-K-Noed\ ;;,t;0 e '*:K S-1{ ;Pension
',' Plans ' aind Otherr PostEoymei L a 7' ; I ; Be efits H Defined benefit plan
' Plan description: OUC maintains a single-employer, defined benefit pension plan for all employees who regularly work'20 or more hours per
' week and were hired prior to Januairy 1, 1998. Under provisions of the pension plan, employees who participate receive a pension benefit equal to 2.5% of the highest three consecutive years average base earnings times years of employment.;A'maximum of 30 years servce is
' credited- Benefitsare vestedafterfiveyears of service.-'-
- OUC isthe administrator of the plan and assuch has t hority to'make anges thereto. Periodically the plan issues standalone financial statements with the most recent report scheduled to be issuec f'r the year ending September 30, 2003. Inaccordance wth Governmental :
Accounting Standards, tpe Plan receives actuarial reports at a minimum bi annually with the mo'strecent actuarial report prepared for the
- period ending Septem oer 30, 2002.- `,'
Funding policy: he pension plan agreement require§s OUC contribute at a minimum amounts actuarially determined.:The current rate of ontribution required by OUC -is'1246/o of 'annual covered payrol Required participant contribution obligations are 4%of earnings until the'
' later of age'62 or completionof 30 years of servicen with noprequired contributions thereaft& Th6 benefit reduction for early retirement is A1%peryear. * * =
ANNUAL REPORT 2003
I I Note K- Pension Plans and Other Post-Employment Benefits (continued)
Annual pension cost and net pension asset OUC recognizes annual pension cost in accordance with GASB Statement No. 27, Accounting for Pensions by State and Local Government Employers. GASB Statement No. 27 also requires recognition of a net pension asset or obligation for the cumulative differences between annual pension cost and employer contributions to the plan. Pension cost and the net pension asset have been calculated using information obtained from actuarial documentation and where applicable, prior year balances have been adjusted to reflect updated actuarial changes and other appropriate reclassifications.
The following schedule summarizes the activity related to the defined pension plan for the years ended September 30, 2003 and 2002:
September 30 (Dollars in thousands) 2003 2002 Current year actuarial required contribution (ARC) $ 4,224 $ 4,251 Interest earnings on net pension asset (141) (126)
Adjustment to ARC 169 166 Annual pension cost 4,252 4,291 Contributions applicable to pension period 4,585 4,317 Change in net pension asset 333 26 Beginning net pension asset 1,473 1,447 Ending net pension asset $ 1,806 $ 1,473 Actuarial reports, received each February, disclose plan assets and actuarial liabilities as of the end of the prior fiscal year and set forth required contribution levels. For the year ending September 30, 2003, OUC received a letter report from the actuary estimating pension costs based on the October 1, 2001 valuation.
Actuarial amounts are calculated using the aggregate cost method, which as noted in guidance, does not identify or separately amortize unfunded actuarial assets/obligations. The actuarial value of assets/obligations isdetermined using techniques that smooth the effects of short-term volatility in the market value of investments over a five-year period. As of September 30, 2003 and 2002, the plan had an unfunded actuarial liability of $54.6 million and $14.5 million, respectively.
In conjunction with the historic low interest rates, OUC in November 2003 issued taxable pension bonds (see Note M) inthe amount of
$55.3 million at a true interest cost of 4.95%. OUC's pension plan earnings rate, used for actuarial purposes, was affirmed by the Pension Committee in2003 and continues to be 8.50%.
In accordance with GASB Statement No. 27, the amounts above were based on the following actuarial information:
October 1 2003 2002 Investment rate of return 8.50% 8.50%
Projected salary increases 5.75% 5.75%
Inflation component 4.00% 4.00%
Three-year trend information Year ending Annual pension cost Percentage of APC (Dollars inthousands) (APC) contributed Net pension asset September 30, 2003 $ 4,252 108% $ 1,806 September 30, 2002 $ 4,291 101% $1,473 September 30, 2001 $ 2,352 98% $ 1,447 OM ANNUAL REPORT 2003
NoeK - Pension lnan d terpPotE poyment Benefits' (ontinUed)
D~efined cotrbtioin pian' .
.All employees who- 6regularly work 20 or more hours per -weekand weiriehired on ior afte anary :1 1998, ~am required to participate ina defined contribution retirement pl~n established uinder section 40 1(a)'of the Internial 'Revenue Code and administered by OUC. !naddition, epoyee hired pri~or t'o January1,l,1998, were offered the option tcovert thei ~iebnftpninacutt hspa.T~pa was created by, resolution of OU.0 . . 7 ~~'.
Une 4hepa,eachf eligible emlyeupon commencement of em0loIriient, isrequired to contribute 4%of their sa ary, With dcmkn a mtcinof4% I aditon OC illr~ath ~p td2%f&additional voluntary ~ontributions. Employees are fully vested after~
cotrbuio one yea r of employment. Total contr'ibutions fort` thyar Setember 30, :2003 and Septiembe~r 30, 2002 were $1.8 million ($870,O000',
5ndn employer and $985,000 employee) and $1.~6 million ($753 6060 employer and $845,000 employee), respectively Other post-emp'loyment benefits ~
OUC has a policy to provide healt cre benefits and life insurne coverage to all employees who- retire' unde the defndbnftpa no
.after attaining age 55 with at least 10 years of service or at a-ny-a'ge after completing 25 years ofsrieCrrently 488 retirees me h eligibility requirements. Retirees may also elect to provid healh cr nuac for hei qulifyindenensbpyg 50% f te calculated p're-miu m.Medical be'nefits will be available, but not subsidized, for employees who retire uner the d efe contribuion pension' plan. OUC isa secondary provider for those'retirees and/or their dependents wh Ir eligibeforiedlicaetneis OU' ealth care plan isadministered through an insurance company on a self-insurance program'WIta diiolpucseisrne p~Ic't oe th~se claims over $150,000. rIn this plan,-the insurance company adrrinisters the plani rcse the clains according to benefit specifications, WithOUC reimb ursing the insurance compan fo its pyusExene aeeordby OU hnpi to the insu rance comnpany. Total post-employment health care costs recoignrized by OUC forthe yasedin Septemnber 30, 2003 and 2002, Were
$3.7 million and $3.2 million, respectively. Po'st-emjloymenit life insurance' costs during' the's'ame periods were $37,000 and $34,000
-Note I~ Lieglation ~and Competition The electric utility industry has been and will be, in-the futurie, affetdbanu erofcosthtoldavanipt on uCt operations.; Althou'gh a handful Of states have enacted legislation or issued orders designed to dereguatetteproduction and sale 'of electricity, no legislative action has been executed in the State ofaForid In20,teGvrnor ofFoia signed an executive order creating the Energy 20StdComsin whose purpose 'was to deina energy strategy and plan for thestate.To fac'ilitate an efective' pathComs ion leted to split thestudy between wholelee adretail, competition. in respect to the wholesale' marketthe Commission recommenided opening the statutory barriers to et~'t lo h cntruction of merchant plants within the state borders.-As for retail competition, itwas the Commission s recommendation'that cnges to'~
thsmretb eered until such time as an efetv opttv hlsl akths been developed. To date no 16~is ative actions have:
been taken -on; thes'e-recommendain In respect to federal leIslto h ERC issued order 2000, requinng theformation of regional transmission organizations. The intention of' this FERC` order 'wa's to'deve lop mar-ket'-driven congestionr mmaagenment as well as Provide onestpsopping for alltanmsso and eliminaite the layering ofratesfor each tra~ismissio'ntrade wichcrosses a corporate boundary. The Staieof Florida began structuring te framework for a statewvide tranismission oanztn(Grid Florida),' and although OUC isnot required to bea rember baed on its municipal U a enivole iiht fmtor fji6 iiai stts hefraonfhsornztinason hold pending a*ruling by Tampa Ecti)triivtedpreiously fied drtoumenths fo~rgtheforationjh of G tindFoiandmkaychgettreosdrd co f E- ~n W
'FoiaV.etme~ h etsesfo ht rnc r rteapiat Fo oe ihPors
I I Note M - Subsequent Events In November 2003, OUC issued the taxable Series 2003T Water and Electric Senior Lien Revenue Bonds, inthe amount of $55.3 million under OUCs General Bond Resolution adopted on October 9, 2001. The Series 2003T Bonds were issued ina fixed rate mode at a true interest cost of 4.95%.
As a result of issuing the Series 2003T bonds, the consent percentage for the Senior Lien Bonds reached the threshold to enact the provisions of the General Bond Resolution. As of November 12, 2003, the consent percentages for Senior and Junior Lien bonds are 52% and 75%, respectively. The terms of the General Bond Resolution are defined in Note H.
In November 2003, OUC's board authorized the dissolution of the agreement with TCS. The offer includes repayment of TCS's capital contributions ($18.1 million) and other amounts owed under the agreement ($854,000) plus an initial lump sum payment for current contracted customers of $5.3 million. Additional payments are contingent on OUC securing additional contracts in certain chilled water operating loops.
ANNUAL REPORT 2003
Deloitte & Touche LLP Certified Public Accountants Suite 1800 200 South Orange Avenue Orlando, Florida 32801 Deloitte Tel: (407) 246-8200 &Touche Fax: (407) 422-0936 www.us.deloitte.com INDEPENDENT AUDITORS' REPORT To the Commissioners of the Orlando Utilities Commission:
We have audited the accompanying statements of net assets of Orlando Utilities Commission as of September 30, 2003 and 2002, and the related statements of revenues, expenses, and changes in net assets and of cash flows for the years then ended. These financial statements are the responsibility of Orlando Utilities Commission's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Orlando Utilities Commission as of September 30, 2003 and 2002, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.
Management's discussion and analysis listed in the Table of Contents 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 lirnited procedures, which consisted principally of inquiries of management regarding the presentation of management's'discussion. However, we did not audit the information and express no opinion on it.
In accordance with Government Auditing Standards, we have also issued a report dated November 17, 2003 on our consideration of Orlando Utilities Commission's internal control over financial reporting and our tests of its compliance with certain provisions of laws, regulations, and contracts. That report is an integral part of an audit performed in accordance with Government A uditing Standards and should be read in conjunction with this report in considering the results of our audits.
November 17, 2003 Deloitte Touche Tohmatsu ANNUAL REPORT 2003
Orlando Utilities Commission 500 South Orange Avenue Orlando, Florida 32801 Phone: 407.423.9100 Fax: 407.236.961 6 The Reliable One' www.ouc.com
PCWATEOUSE(O4PEPS X Seminole Electric Cooperative, Inc.
Consolidated Financial Statements For the Years ended December 31, 2003 and 2002
RI~CEWATERHOUSE(OPER X PricewaterhouseCoopers LLP 101 East Kennedy Boulevard Suite 1500 Tampa FL 33602-5147 Telephone (813) 229 0221 Facsimile (813) 229 3646 Report of Independent Certified Public Accountants To the Board of Trustees Seminole Electric Cooperative, Inc.
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of revenue and expenses and patronage.capital, of comprehensive income and of cash flows present fairly, in all material respects, the financial position of Seminole Electric Cooperative, Inc. and its subsidiaries ("Seminole") at December 31, 2003 and 2002, and the results of their operations and their cash flows for the years then ended, in confornity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of Seminole'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 and the standards applicable to financial audits contained in Government Auditing Standards,issued by the Comptroller General of the United States, which 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 provides a reasonable basis for our opinion.
In accordance with Government Auditing Standards,we have also issued our report dated February 13, 2004 on our consideration of Seminole's internal control over financial reporting and on our tests of its compliance with certain provisions of laws, regulations, contracts and grants. That report is an integral part of an audit performed in accordance with Government Auditing Standardsand should be read in conjunction with this report in considering the results of our audit.
eW., onLu mrJzI r cruway 1A, zuu i
SEMINOLE ELECTRIC COOPERATIVE, INC.
CONSOLIDATED BALANCE SHEETS December 31 2003 2002 ASSETS Utility plant:
Plant in service $ 1,074,460,489 $ 1,072,706,869 Construction work in progress 11,319,061 4,056,718 1,085,779,550 1,076,763,587 Less accumulated depreciation and amortization (441,205,429) (416,466,162)
Utility plant, net 644,574,121 660,297,425 Investments:
Investments in associated organizations 2,998,556 3,460,364 Funds held by trustees and special funds 66,729,025 63,439,520 Total investments 69,727,581 66,899,884 Current assets:
Cash and cash equivalents 25,927,301 24,428,385 Other current investments 39,947,986 0 Receivables, principally for sales of electricity 81,876,569 79,749,297 Inventories, at average cost:
Materials and supplies 19,460,382 19,039,303 Fuel 15,284,326 31,042,863 Prepayments and other 10,724,020 7,252,074 Total current assets 193,220,584 161,511,922 Deferred charges:
Regulatory 23,419,972 36,042,042 Non-Regulatory 36,166,158 38,457,274 Total deferred charges 59,586,130 74,499,316 Total assets $ 967,108,416 $ 963,208,547 The accompanying notes are an integral part of these consolidated financial statements.
SEMINOLE ELECTRIC COOPERATIVE, INC.
CONSOLIDATED BALANCE SHEETS December 31 2003 2002 EQUITIES AND LIABILITIES Equities:
Memberships $ 1,000 S 1,000 Patronage capital 76,927,550 75,098,372 Donated capital 31,715 31,715 Other margins and equities 3,917,839 4,393,321 Total equities 80,878,104 79,524,408 Long-term liabilities:
Long-term debt 755,538,777 748,589,639 Obligations under capital leases 0 285,872 Other 14,485,177 7,600,213 Total long-term liabilities 770,023,954 756,475,724 Current liabilities:
Current portion of:
Long-term debt 35,084,307 31,547,242 Obligations under capital leases 285,872 262,762 Accounts payable 34,117,411 40,769,302 Other accrued liabilities 27,955,761 29,360,460 Total current liabilities 97,443,351 101,939,766 Deferred gain on sale-leaseback of plant 8,435,622 9,851,391 Other deferred credits 10,327,385 15,417,258 Commitments and contingencies (Notes 10 and 11)
Total equities and liabilities S 967,108,416 $ 963,208,547 The accompanying notes are an integral part of these consolidated financial statements.
SEMINOLE ELECTRIC COOPERATIVE. INC.
CONSOLIDATED STATEMENTS OF REVENUE AND EXPENSES AND PATRONAGE CAPITAL For the years ended December 31, 2003 2002 Operating revenues $ 798,693,898 $ 713,770,716 Operating expenses:
Operation:
Fuel 270,128,732 234,142,855 Other production expenses 76,821,190 75,253,835 Purchased power 296,893,984 242,448,133 Transmission 38,874,366 38,846,162 Administrative and general 19,406,851 23,414,642 Depreciation and amortization - non-fuel 34,221,348 33,052,714 Lease of coal-fired plant 26,647,435 27,114,994 Total operating expenses 762,993,906 674,273,335 Operating margins before interest expense 35,699,992 39,497,381 Interest expense, net of amounts capitalized 40,277,839 42,071,213 Operating deficits (4,577,847) (2,573,832)
Patronage capital credits 26,129 29,511 Net operating deficits after interest expense (4,551,718) (2,544,321)
Non-operating income:
Interest income 4,183,771 4,762,831 Other income, net 2,784,514 131,047 Net margins 2,416,567 2,349,557 Patronage capital, beginning of year 75,098,372 73,352,675 Patronage capital retirements (587,389) (603,860)
Patronage capital, end of year $ 76,927,550 $ 75,098,372 The accompanying notes are an integral part of these consolidated financial statements.
SEMINOLE ELECTRIC COOPERATIVE, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME For the years ended December 31, 2003 2002 Net margins $ 2,416,567 $ 2,349,557 Other comprehensive income/(loss):
Cash flow hedges:
Beginning balance 4,393,321 (990,383)
Unrealized gain on derivatives 8,376,673 8,535,422 Less: Reclassification adjustment for derivative income included in net margins 8,852,155 3,151,718 Other comprehensive income 3,917,839 4,393,321 Comprehensive income $ 6,334,406 $ 6,742,878 The accompanying notes are an integral part of these consolidated financial statements.
SEMINOLE ELECTRIC COOPERATIVE, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS For the years ended December 31, 2003 2002 Cash flows from operating activities:
Net margins $. 2,416,567 $ 2,349,557 Adjustments to reconcile to cash:
Depreciation and amortization 51,524,106 55,035,759 Amortization of deferred gain on lease/leaseback (1,240,811) (1,198,442)
Lease expense/lease payment difference (344,878) 346,857 Change in assets and liabilities:
Receivables (2,135,028) (12,258,831)
Inventories 15,337,458 (6,246,044)
Prepayments and other (4,988,996) 141,030 Deferred charges (1,748,256) (3,228,124)
Other-long-term liabilities (1,369) (1,546)
Accounts payable (6,651,891) 5,200,067 Other accrued liabilities (233,352) (12,939,586)
Total adjustments 49,516,983 24,851,140 Net cash provided by operating activities 51,933,550 27,200,697 Cash flows from investing activities:
Utility plant additions, net of retirements (17,935,236) (11,908,457)
(Purchases of)/proceeds from investments, net (39,939,720) 6,600,145 Net cash used in investing activities (57,874,956) (5,308,312)
Cash flows from financing activities:
Proceeds from long-term borrowings 39,838,000 0 Payments of long-term debt (31,547,527) (29,649,593)
Payments of capital lease obligations (262,762) (241,521)
Payments of patronage capital credits (587,389) (603,860)
Net cash provided by/(used in) financing activities 7,440,322 (30,494,974)
- Net increase/(decrease) in cash and cash equivalents 1,498,916 (8,602,589)
Cash and cash equivalents, beginning of year 24,428,385 33,030,974 Cash and cash equivalents, end of year $ 25,927,301 $ 24,428,385 Supplemental disclosure: Interest paid $ 36,039,031 $ 37,808,522 The accompanying notes are an integral part of these consolidated financial statements.
SEMINOLE ELECTRIC COOPERATIVE. INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1 - THE COOPERATIVE:
Seminole Electric Cooperative, Inc. (Seminole) is a generation and transmission cooperative (G & T). It is responsible for meeting the electric power and energy needs of its distribution cooperative members operating within the State of Florida. Seminole's rates are established by its Board of Trustees, which is composed of representatives from each member cooperative.
Seminole constructed and operates Seminole Generating Station (SGS) comprised of two coal-fired generating facilities (Seminole Unit No. I and Unit No. 2) near Palatka, Florida with approximately 650 megawatts of net output per unit. These units are connected to the Florida bulk power supply grid through Seminole's 230 kV transmission lines and associated facilities.
Both units commenced commercial operation in 1984.
On January 1, 2002, the Payne Creek Generating Station (PCGS) commenced commercial operation. PCGS is a 500 megawatt, gas-fired combined cycle generating facility constructed by Seminole on an existing 1,300 acre site leased from Acuera Corp. (Acuera), a wholly owned l subsidiary of Seminole.
At December 31, 2003, 170 employees or approximately 36% of the total workforce were covered by a four year collective bargaining agreement with Utility Workers Union of America expiring on June 30, 2007.
Lk Seminole holds a 1.6994% undivided ownership interest in the Crystal River Unit No. 3 (CR3) nuclear power plant operated by Progress Energy Florida (PEF). Seminole also owns various transmission facilities connecting Seminole to an Independent Power Producer (IPP) as well as individual members to the Florida bulk power grid.
NOTE 2 -
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES:
Seminole complies with the Uniform System of Accounts as prescribed by the Rural Utilities Service (RUS). The accounting policies and practices applied by Seminole in the determination of rates are also employed for financial reporting purposes. These policies and practices require management to make estimates and assumptions that affect the reported amounts of assets and liabilities, 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. Under the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation, Seminole's Board of Trustees prescribes rate-making recovery for certain transactions.
The consolidated financial statements include the results of operations and financial position of Seminole, Acuera, Putnam Leasing Company A, Inc., Putnam Leasing Company B, Inc., and Putnam Leasing Company C, Inc., each wholly owned subsidiaries of Seminole. Acuera owns a 1,300 acre site in Hardee County and Polk County, Florida, a portion of which is leased on a
nonexclusive basis to an IPP for its use associated with certain generating facilities constructed and owned by the IPP. The three leasing subsidiaries were established to facilitate the completion of the lease/leaseback transactions relating to one of Seminole's coal-fired generating facilities. All significant intercompany transactions have been eliminated.
Operating Revenue Seminole has wholesale power contracts with each of its members, whereby the members must purchase all electric power and energy which the member shall require for the operation of its system within the State of Florida from Seminole to the extent that Seminole shall have such power, energy and facilities available. The only exception relates to contracts between several members and the Southeastern Power Administration, which provides less than 1% of the total energy required by all members.
Operating revenue consists primarily of sales of electric power and energy by Seminole, a facilities use charge for Seminole's transmission lines serving a single member cooperative, and by-product sales. Member revenues include amounts resulting from a fuel and purchased power adjustment clause which provides for billings to reflect increases or decreases in fuel and fuel related purchased power costs. The levelized fuel rate is based on costs projected by Seminole for a twelve-month period. Any over-recovery or under-recovery of costs plus an interest factor are to be refunded or billed to the members semi-annually. At the members option, refunds of over-recoveries may be deferred with interest every six months until such time as the member elects to have the over-recovery including accumulated interest refunded.
Over-recoveries of approximately $1.6 million and under-recoveries of approximately $9.9 million at December 31, 2003, and 2002, respectively, are recorded in accrued liabilities or accounts receivable until refunded or billed.
Included in operating revenue are approximately $774 million and $696 million of revenue from members for the years ended December 31, 2003 and 2002, respectively, of which approximately $79 million and $68 million primarily related to December sales are included in receivables at December 31, 2003 and 2002, respectively.
Utility Plant Utility plant owned by Seminole is stated at original cost. Such cost includes applicable supervisory and overhead cost, plus net interest charged during construction. The amounts of interest capitalized during 2003 and 2002 were approximately $0.4 million and $0.2 million, respectively. The cost of maintenance and repairs, including renewals and replacements of minor items of property, is charged to operating expense. The cost of replacement of depreciable property units, as distinguished from minor items, is charged to utility plant. The cost of units replaced or retired, including cost of removal, net of any salvage value, is charged to accumulated depreciation. (See Accounting for Asset Retirement Obligations.) Certain leased transportation equipment is valued at the total net present value of minimum lease payments.
Depreciation and Amortization of Utility Plant Seminole provides for depreciation on owned utility plant using composite rates applied annually on a straight-line basis that will amortize the original cost of depreciable property over its estimated useful life. The average rates for 2003 and 2002 were as follows:
2003 2002 Coal-fired production plant 3.10% 3.10%
Combined cycle production plant 3.00% 3.00%
_ Transmission plant 2.75% 2.75%
General plant 7.94% 8.22%
Nuclear production plant 4.51% 4.51%
Depreciation expense amounted to approximately $31.3 million and $31.1 million for 2003 and 2002, respectively.
Improvements to the leased coal-fired production plant are amortized over the remaining life of the base lease term. The related composite amortization rates were 7.37% and 7.18% for 2003 and 2002, respectively.
Amortization of leased assets under capital leases amounted to approximately $0.3 and $0.2 million in 2003 and 2002, respectively.
Long-Lived Assets Seminole evaluates, on a regular basis, whether events and circumstances have occurred that indicate the carrying amounts of utility plant and deferred charges may warrant revision or may not be recoverable. Seminole measures impairment of these long-lived assets based on estimated future undiscounted cash flows from operations. At December 31, 2003, the net utility plant and net unamortized deferred charges balances are not considered to be impaired.
Accounting for Asset Retirement Obligations Seminole adopted SFAS No. 143, "Accounting for Asset Retirement Obligations" effective January 1, 2003. The statement requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. Seminole has reviewed all of our assets. Seminole has no legal obligation to retire any asset except for Seminole's share in decommissioning the CR3 nuclear plant.
The CR3 decommissioning asset retirement obligation has been calculated as the fair value at CR3's initial start of operations, January 1, 1977. The fair value has been calculated using a site specific study, using Seminole's credit-adjusted risk-free interest rate. Decommissioning expenditures are expected to occur over a twenty-six year period ending in 2041. The initial
fair value has been increased by accretion to a value of $6.1 million at January 1, 2003. 2003 accretion increased this to $6.6 million at December 31, 2003. This liability is shown in long-term liabilities. Seminole previously had a liability for CR3 decommissioning shown in deferred credits. The value of this previous liability was $4.7 million at December 31, 2002. The transition adjustment has been deferred as a regulatory asset, under a SFAS No. 71 expense deferral plan.
Seminole has established an external nuclear decommissioning trust fund (NDTF) in compliance with regulations prescribed by the Nuclear Regulatory Commission. The trust fund balance is $5.5 million at December 31, 2003. Annual cash deposits will be made to the NDTF to bring it in line with the obligation to decommission CR3. An amount equal to these cash deposits will be expensed annually and collected through rates to members.
Amortization of Deferred Gain on Sale-Leaseback Deferred gain on sale-leaseback of coal-fired production plant is being amortized on a straight-line basis over the base lease term of twenty-five years commencing in 1985 and is reflected as a reduction of operating expenses. Amortization for 2003 and 2002 was $1.4 million.
Gain on Lease/Leaseback In December 1997, Seminole entered into three long-term lease/leaseback transactions for a portion of its Palatka generating station. These transactions are characterized as sales and leasebacks for income tax purposes, but are reflected as financing transactions for financial reporting purposes. Beginning in 1998, the net cash benefit to Seminole totaling approximately $28.2 million is being recognized on a straight-line basis over the twenty-three year leaseback period in the amount of approximately $1.2 million annually pursuant to SFAS No. 71 and as authorized by the Board of Trustees.
Deferred Charcqes: Regulatory In December 1998, the Seminole Board of Trustees authorized the implementation of an expense deferral plan pursuant to the provisions of SFAS No. 71 relating to costs to be incurred associated with the termination of certain coal transportation contracts. At December 31, 2003 and 2002, deferred charges included the unamortized balance of $13.2 million and
$27.4 million, respectively, related to marine equipment lease termination costs, operating costs of the leased marine equipment subsequent to coal transportation contract terminations and prior to sale, and certain other costs which have been deferred pursuant to this plan. The deferred costs associated with the coal transportation contract terminations are being amortized to fuel expense on a cost per ton basis through 2004, reflecting the shortest remaining term of the contracts terminated. Amortization of deferred costs associated with the coal transportation contract terminations was approximately $14.2 million in 2003 and 2002.
In May 2003, the Seminole Board of Trustees authorized the implementation of an expense deferral plan pursuant to the provisions of SFAS No. 71 relating to the CR3 decommissioning
asset retirement obligation transition adjustment and subsequent accounting (see Asset
- Retirement Obligations.) At January 1, 2003 and December 31, 2003 regulatory deferred charges included $1.1 and $0.9 million, respectively, of net CR3 decommissioning asset retirement obligation transition adjustment.
Also included in regulatory deferred charges is the net book value of $7.5 million and $7.4 million at December 31, 2003 and 2002, respectively relating to the straight line recognition of the gain on the lease/leaseback transactions.
Also included in regulatory assets is $1.9 and $1.3 million as of December 31, 2003 and 2002 respectively, are unrealized losses relating to the ineffective portion of put premiums on gas hedging. These losses will be expensed as the gas is purchased.
Deferred Charges: Non-Regulatory At December 31, 2003 and 2002, non-regulatory deferred charges included unamortized debt costs and related refinancing premiums of approximately $34.1 million and $36.5 million, respectively. These deferred charges will be recovered through rates over the remaining lives of the related debt ranging up to seventeen years. Amortization of these deferred charges amounted to approximately $2.5 million in 2003 and 2002.
Other non-regulatory deferred charges include primarily software costs. Capitalized software costs are accounted for under Statement of Position 98-1, "Accounting for the Costs of Computer Software Developed or Obtained for Internal Use" (SOP 98-1), and are included in deferred charges at cost less accumulated amortization. These costs are being amortized over periods up to five years. The amount capitalized under SOP 98-1 as of December 31, 2003 and December 31, 2002 was $2.4 million and $2.0 million, respectively. Amortization in 2003 and 2002 totaled approximately $0.4 and $0.2 million, respectively.
Other Deferred Credits At December 31, 2003 and 2002, other deferred credits primarily included deferred lease expense which represents the difference between cash payments and expense recognized on a straight-line basis related to the operating lease of certain generating facilities, and a reserve for CR3 decommissioning costs. The CR3 decommissioning liability at December 31, 2002, was moved to other long-term liabilities in 2003 (see Asset Retirement Obligations.) These deferred credits are non-regulatory and have been authorized by the Board of Trustees.
Accounting for Derivatives and Hedging Activities All derivatives are recognized on the balance sheet at their fair value and changes in fair value of those instruments are recognized as either a component of comprehensive income or in net income, depending on the types of those instruments. On the date that Seminole enters into a derivative contract, Seminole determines whether the derivative is subject to the requirements of SFAS 133 or meets the criteria for exclusion. All contracts requiring SFAS 133 accounting
are designated as cash flow hedges, fair value hedges, or as a trading instrument, and formal documentation of relationships between hedging instruments and the hedged items, hedging objective and strategy, and methods for assessing hedge effectiveness both at the hedge's inception and on an ongoing basis is completed. All components of each derivative's gain or loss have been included in the assessment of hedge effectiveness.
To reduce the exposure to natural gas price fluctuation risks, Seminole entered into natural gas hedging transactions, futures and puts, in 2003 and 2002. The future transactions are designated as cash flow hedges and are deemed to be highly effective. The put transactions have a component of the fair value that is ineffective. The ineffective component of the put has been deferred to regulatory assets under a SFAS No. 71 expense deferral plan. Both components of the fair value will be reclassified into earnings as the gas is purchased. For the years ended December 31, 2003 and 2002, net gains of $8.9 million and $4.2 million, respectively, were reclassified into earnings and are included in uFuel" or "Purchased Power" in the Consolidated Statement of Revenue and Expenses and Patronage Capital. Other Comprehensive Income reflects a $4.0 million and $5.4 million gain related to the future transactions as of December 31, 2003 and 2002, respectively. Regulatory deferred charges reflects a $1.9 and $1.3 million loss related to the ineffective components of the puts at December 31, 2003 and 2002, respectively. Based on fair values at December 31, 2003, approximately $2.0 million net gain at December 31, 2003 is expected to be reclassified into earnings and included in "Fuel" or "Purchased Power" within the next twelve months as gas is purchased. In 2002, Seminole established a NYMEX margin account to facilitate the gas hedging transactions for 2003 and beyond. This margin account is included in "Prepayments and Other" on the Consolidated Balance Sheet. Seminole made an initial deposit for this account and must keep a maintenance margin. The fair market value changes to this account resulted in excess margins of approximately $3.8 and $3.7 million at December 31, 2003 and December 31, 2002, respectively. Seminole has a right to call for cash payment from the excess margin, and did so several times in 2003 and in January, 2004.
On December 13, 2001, Seminole entered into a two-year agreement to swap the variable interest rate on a portion of the pollution control revenue bonds, on which the interest rate varies weekly, for a fixed interest rate of 2.99%. The transaction is designated as a cash flow hedge and is deemed highly effective, and therefore no ineffective losses were recognized in earnings for 2003 and 2002. Other Comprehensive Income reflects losses of $.03 million and
$1.0 million related to the interest rate swap transaction as of December 31, 2003 and 2002 respectively. The losses are reclassified into earnings when the underlying pollution control revenue bond interest is incurred. This transaction terminates January 15, 2004.
Cash Equivalents Seminole considers all short-term, highly liquid investments with an original maturity of three months or less to be cash equivalents.
Consolidation of Variable Interest Entities In December 2003, the Financial Accounting Standards Board issued FASB Interpretation No.
46 (revised December 2003), "Consolidation of Variable Interest Entities", an interpretation of Accounting Research Bulletin No. 51, "Consolidated Financial Statements" which is effective for nonpublic enterprises by the beginning of the first annual period beginning after December 15, 2004. This interpretation requires that an enterprise that consolidates a variable interest entity is the primary beneficiary of the variable interest entity. Seminole will adopt FASB Interpretation No. 46 on January 1, 2005, and, based on current circumstances, does not believe that the impact of adoption of this interpretation will have a material impact on Seminole's financial position or results of operations.
Reclassifications Certain reclassifications have been made to the 2002 statements to conform to current classifications. There were no changes to net margins as previously reported.
NOTE 3 - UTILITY PLANT:
December 31, 2003 2002 Owned property:
Coal-fired production plant $ 601,908,399 $ 606,429,177 Combined cycle plant 228,235,497 225,378,876 Transmission plant 168,588,198 168,252,074 General plant 23,953,767 23,176,516 Nuclear plant, including fuel 25,359.706 23,133,836 1,048,045,567 1,046,370,479 Transportation equipment under capital leases 2,538,591 2,538,591 Leasehold improvements of coal-fired production plant 23,876,331 23,797,799 1,074,460,489 1,072,706,869 Construction work in progress 11.319,061 4,056,718 1,085,779,550 1,076,763,587 Accumulated depreciation and amortization:
Owned property (425,540,471) (402,610,171)
- Leased transportation equipment ( 2,369,323) ( 2,097,134)
Leasehold improvements ( 13,295,635) ( 11,758.857)
(441,205,429) (416,466,162)
$ 644.574.121 $ 660.297.425
NOTE 4-INVESTMENTS:
December 31, 2003 2002 Investments in associated organizations:
CFC:
Membership $ 1,000 $ 1,000 Capital term certificates 1,442,520 1,445,721 Subordinated term certificates 1,033,635 1,473,213 Patronage capital certificates 491,154 505,084 Other 30,247 35.346
$ 2.998.556 $ 3,460.364 Funds held by trustees and special funds:
Pollution control bond funds $ 15,494,628 $ 15,599,664 Nuclear decommissioning trust fund 5,506,795 4,740,732 Lease termination fund 45.727,602 43,099,124
$ 66.729,025 $ 63.439.520 Other Current Investments $ 39.947.986 $ 0 Investments in capital and subordinated term certificates and patronage capital certificates are considered to be held-to-maturity investments due to their nature and are carried at cost determined by specific identification.
It is not practical to estimate the fair value of CFC capital term certificates due to the nature and maturity of these investments. Of these investments, $1,442,520 are required as a condition of membership and of loans provided to Seminole by CFC. Of the approximately
$1.4 million carrying amounts at December 31, 2003 and 2002, $63,307 matures in 2075 and
$918,124 matures in 2080. Both of these amounts pay 5% annual interest. Additionally,
$364,283 matures in 2030 and pays 3% annual interest, and $96,806 in 2003 and $100,007 in 2002, bears no interest and amortizes through 2019.
Investments in CFC subordinated term certificates are required as a condition of guarantees provided to others by CFC on behalf of Seminole and are generally priced at market rates at the time of issuance. These investments bear interest at various rates with a combined average of approximately 5.6% and 5.9% at December 31, 2003 and 2002, respectively. At December 31, 2003 and 2002, the estimated fair values of these investments of approximately
$1.0 million and $1.5 million, respectively, are based on the current rates offered by CFC for this type of required investment.
Funds held by trustees for pollution control bond funds are recorded at amortized cost and are considered to be held-to-maturity investments. The investments in the nuclear decommissioning trust fund (NDTF) are also considered held-to-maturity except for certain investments held by the NDTF which are invested in equity mutual funds and are valued at
market prices. During 2003, the fair value related to the NDTF equity securities, which are available for sale, increased approximately $0.3 million. At December 31, 2003 and 2002, the estimated fair values of these funds of approximately $21.0 million and $20.3 million, respectively, are based on quoted market prices for the securities held by the trustees.
The lease termination fund, which has been invested in zero coupon government securities with a yield of 6.1%, will be held to maturity (2020) and is not marketable; therefore, the fair market value is not determinable.
Other Current Investments The amount shown in other current investment at December 31, 2003, includes a CFC medium term note to be held-to-maturity. The interest rate is 1.86% and it matures December 15, 2004. At December 31, 2003, the estimated fair value of this investment is approximately
$39.9 million and is based on quoted market prices offered by CFC for this type of investment.
NOTE 5 - LONG-TERM LIABILITIES:
Long-Term Debt December 31, 2003 2002 First mortqage notes payable to Federal Financing Bank (FFB),
guaranteed by RUS, principal due in various installments through 2020, Interest at fixed rates, from 4.458% to 7.295% $587,749,604 $573,366,396 First mortgage notes payable to RUS, principal due in various installments through 2019, interest at 5.00% 6,174,592 6,496,402 Pollution control revenue bonds payable to the Putnam County Develop-ment Authority, guaranteed by CFC, principal due in various installments through 2014, interest at adjustable rates, currently 3.28% and 1.02% 114,850,000 120,350,000 First mortgage notes payable to CFC,
! principal due in various installments through 2019, interest at adjustable rates, currently 2.55% 7,584,259 7,855,183
Lease termination obligation payable To State Street Bank and Trust at maturity in 2020, interest imputed at a fixed rate of 3.05% 74.264,629 72,068,900 790,623,084 780,136,881 Less current portion ( 35,084,307) ( 31,547,242)
$755.538.777 $748,589.639 The estimated maturities and annual sinking fund requirements of all long-term debt, at interest i rates as of December 31, 2003 for the four years subsequent to December 31, 2004, are presented below:
Annual Maturities Year ending and Sinking Fund December 31. Requirements 2005 $ 37,581,051 2006 $ 40,031,435 2007 $ 42,665,802 2008 $ 61,972,674 2009 $ 62,508,445 On November 5, 2003, the remaining available FFB debt in the amount of $39.8 million was drawn at an effective interest rate of 4.458%.
Substantially all owned assets and leasehold interests other than the lease termination fund
- are pledged as collateral for the above mentioned debt to the United States of America (RUS and FFB) and CFC. The lease termination fund is pledged as collateral for the lease termination obligation to State Street Bank and Trust.
At December 31, 2003 and 2002, the estimated fair value of long-term debt including current portion but excluding the lease termination obligation, is approximately $787 million and $798 million, respectively. For Seminole's long-term debt with interest rates substantially fixed to final maturity, and for that portion that is subject to interest rate adjustment more than six i months from year end, fair value is estimated based on the present value of the underlying cashflows. For that portion of long-term debt that reprices to market rates at intervals of six months or less, the carrying amount has been used as a reasonable estimate of fair value.
The fair value of the lease termination obligation is not determinable since it is not marketable.
Obligations Under Capital Leases At December 31, 2003, Seminole was obligated under a capital lease of rail transportation equipment which base lease term expires in 2004. The following is a schedule of future lease payments under the lease together with the present value of the net minimum lease payments as of December 31, 2003:
Year ending December 31.
2004 $ 304,461 Thereafter 0 Total minimum lease payments 304,461 Less amount representing interest (18589)
Present value of minimum lease payments 285,872 Less current principal portion (285,872)
$ 0 This transportation equipment lease provides for renewal and option to purchase the equipment at fair market value at various dates or upon expiration. During 2003 and 2002, payments under the rail transportation equipment lease in the amount of approximately $0.3 million were included as a cost of fuel inventory and expensed based on the tons of coal burned throughout the year.
NOTE 6 - NET MARGINS AND EQUITY RESTRICTIONS:
Under provisions of the RUS mortgage, until total equity equals or exceeds forty percent of total assets, the distribution of capital contributed by members is limited generally to twenty-five percent of patronage capital and margins of the next preceding year where, after giving effect to such distribution, the total equity will equal or exceed twenty percent of total assets. Distributions may be made, however, in such amounts as may be approved by RUS through waiver of the aforementioned restrictions. Such distributions to members totaled
$587,389 and $603,860 in 2003 and 2002, respectively, representing amounts equal to 25% of 2002 and 2001 net margins, respectively. The RUS mortgage requires Seminole to design its wholesale rates with a view towards maintaining, on a calendar year basis, a Times Interest Earned Ratio (as defined in the agreement) of not less than 1.0 and a Debt Service Coverage Ratio (as defined in the agreement) of not less than 1.0. An RUS stipulation arising from the sale of tax benefits requires Seminole to design its wholesale rates to provide an annual Times Interest Earned Ratio of not less than 1.05.
In 2003 and 2002, Seminole achieved a Times Interest Earned Ratio of 1.05, and a Debt Service Coverage Ratio of 1.05 and 1.07 respectively.
NOTE 7 - LINES OF CREDIT:
Seminole has available lines of credit totaling $75 million, of which $25 million is committed and $50 million is uncommitted. None of these were drawn at December 31, 2003 and 2002.
RUS policy governs use of these funds.
NOTE 8 - INCOME TAXES:
Seminole is a non-exempt cooperative subject to federal and state income taxes and files a consolidated tax return. As a cooperative, Seminole is entitled to exclude patronage dividends from taxable income. Seminole's bylaws require it to declare patronage dividends in an aggregate amount equal to Seminole's federal taxable income from its furnishing of electric
energy and other services to its member-patrons. Accordingly, such income will not be subject to income taxes.
Seminole's rate-making methods provide that any income taxes related to current operations are recognized as expense and are recovered through rates when currently payable. In addition, income tax credits are accounted for as a reduction of taxes currently payable in the period utilized. In 2003 and 2002, net operating losses of approximately $33,000 and $3.4 million, respectively, were generated from non-patronage activity. At December 31, 2003, net operating losses of approximately $58.2 million are available to offset future taxable income, expiring in years through 2023. Furthermore, alternative minimum tax (AMT) credits of approximately $1.0 million, which do not expire, are available to offset regular income tax liabilities.
Temporary differences in certain items of income and expense for tax and financial reporting purposes result primarily from depreciation, amortization and sale-leaseback of plant.
Seminole has recorded the following noncurrent deferred tax asset, valuation allowance and noncurrent deferred tax liability in 2003 and 2002:
2003 2002 Noncurrent deferred tax asset $22,900,000 $30,800,000 Less: Valuation allowance (22,900,000) (30,800,000)
Net noncurrent deferred tax asset 0 0 Noncurrent deferred tax liability 0 0 Net noncurrent deferred tax $ 0 $ 0 asset/liability Seminole excludes from its taxable income amounts derived from patronage activity. The deferred tax asset, valuation allowance and deferred tax liability are calculated solely based on non-patronage activity.
IThe noncurrent deferred tax asset reflects deductible temporary differences and net operating loss carryforwards at statutory rates, plus investment tax credits (through 2002) and AMT credits. Based on Seminole's historical transactions and the exclusion of patronage dividends L_ from taxable income, it is not anticipated that Seminole will have future taxable income sufficient to fully realize the benefit of the existing tax credits and net operating loss carryforwards at December 31, 2003. A valuation allowance has been recorded to reduce deferred tax assets relating to tax credits and net operating loss carryforwards. The valuation allowance decreased from 2002 to 2003 due to the expiration of net operating loss carryforwards and investment tax credits, and a reduction of AMT credits due to a refund of previously paid AMT.
The noncurrent deferred tax liability reflects taxable temporary differences at statutory rates.
NOTE 9 - EMPLOYEE BENEFITS:
Substantially all Seminole employees participate in the National Electric Cooperative Association (NRECA) Retirement and Security Program (the Program), a defined benefit pension plan qualified under Section 401 and tax exempt under Section 501 (a) of the Internal
Revenue code. In this multi-employer plan, which is available to all member cooperatives of NRECA, the accumulated benefits and plan assets are not determined or allocated separately by individual employer. Due to the nature of the multi-employer plan, specific employer information is not available. Seminole also has a retirement savings plan for all employees that is qualified under Section 401 (k) of the Internal Revenue Code.
The following lists Seminole's pension obligations:
2003 2002 NRECA Pension Plan $ 3,745,000 $ 3,296,000 401 (k) Savings Plan $ 654,000 $ 655,000 All employees are eligible to participate in the group health care coverage plan. Under this plan most employees have an option to choose either the Preferred Provider Plan or the Health Maintenance Organization Plan. Employees retiring on or after age 55 receive the benefit of being allowed to continue, at their expense, health care coverage under Seminole's group plan. In addition, these retirees may use a portion of their accumulated unused sick pay to apply toward these medical insurance premiums.
The following sets forth the plan's status reconciled with amounts reported in Seminole's consolidated balance sheets at December 31, 2003 and 2002. The plan is funded on a pay-as-you-go basis.
Accumulated postretirement benefit obligation (APBO):
2003 2002 Active plan participants not yet fully eligible $ 2,759,400 $ 2,958,400 Fully eligible active plan participants 1,457,000 1,288,800 Retirees and dependents 522,200 302,800 Other plan participants 60,200 49,900 Total APBO 4,798,800 4,599,900 Unrecognized gain from past experience 1,544,900 1,391,900 Unrecognized prior service cost 277,400 318,000 Accrued postretirement benefit liability $ 6,621,100 $ 6,309,800
Net periodic postretirement benefit included the following components:
Service cost $ 349,800 $ 308,200 Interest cost on accumulated benefit obligation 287,800 285,700 Amortization of actuarial gain (79,200) (69,700)
Amortization of prior service cost (40,600) (40,600)
Net periodic postretirement benefit cost $ 517,800 $ 483,600 These costs are based on assumptions in interest rates and health care trends as listed below which reflect Seminole's best estimate of the plan's future expense, and is based on current active and retired plan participants.
2003 2002 Discount Rate 6.75% 7.00%
Rate of Compensation increase 3.50% 4.50%
Health care cost trend rate 14.00% 9.00%
Rate which the cost trend rate is assumed to decline (the ultimate trend rate) 5.50% 5.50%
Year that the rate reaches the ultimate trend rate 2012 2009 The health care cost trend rate assumption has a significant effect on the amounts reported.
For example, a 1% increase in the health care trend rate would increase the accumulated post-retirement benefit obligation by $268,100 or 5.5% at year-end 2003 and net periodic cost by $42,100 or 6.6% for the year. The net effect of changes in assumptions for health care cost trend rates, and weighted average discount rate caused an increase in the APBO at December 31, 2003. The unrecognized net gain in excess of ten percent of the APBO is being amortized over the fifteen remaining service years of active plan participants, in the amount of $79,200 per year.
Seminole expects to contribute $4,816,000 to its pension and 401 (k) plans, and $530,000 to its other postretirement benefit plan in 2004.
NOTE 10- OPERATING LEASES:
At December 31, 2003, Seminole was obligated under certain leases of generating facilities and rail transportation equipment for which base lease terms expire on various dates through 2009. The lease of the generating facilities contains a variable interest rate component that could affect future lease payments. Base rental obligations under these leases are payable as follows:
Year ending December 31, 2004 $ 37,656,000 2005 $ 38,334,000 2006 $ 38,522,000 2007 $ 38,555,000 2008 $ 38,588,000 Thereafter $ 36,163,000 These leases generally provide for renewals at the lower of a stipulated fixed renewal rental or fair market rental and options to purchase facilities and/or equipment at fair market value at various dates or upon expiration. Lease payments for the rail transportation equipment leases totaled approximately $2.5 million in 2003 and 2002. These payments were included as a cost of fuel inventory and expensed based on the tons of coal burned throughout the year.
NOTE 11 - COMMITMENTS AND CONTINGENCIES:
Seminole is purchasing a significant portion of the coal for SGS under a long-term contract expiring in 2010. Contract terms specify minimum annual purchase commitments of 2.25 million tons, subject to force majeure conditions, and prices which are subject to adjustment for changes in costs. Total purchases under this long-term coal contract were approximately
$51.9 million and $67.6 million in 2003 and 2002, respectively.
Seminole is required to transport a significant portion of its coal and petroleum coke to be received at SGS under an agreement with a rail carrier, such agreement expiring no earlier than December 31, 2006. Total charges under this contract were approximately $51.7 million and $55.6 million in 2003 and 2002, respectively.
Seminole has long-term contracts for the transportation of natural gas for PCGS terminating in 2020. These contracts require annual capacity reservation payments for the next five years (2004 through 2008) of $13.2 million per year. The capacity reservation payments are partially based on proposed rates by Florida Gas Transmission Company in Federal Energy Regulatory Commission (FERC), Docket Number RP-04-012-000, which are subject to refund if ordered by FERC.
Seminole has various firm contracts with suppliers for purchased power with remaining terms ranging from one to ten years. These contracts require annual minimum take-or-pay capacity payments for the next five years as follows:
Year ending December 31, 2004 $ 96,300,000 2005 $ 107,900,000 2006 $ 117,500,000 2007 $ 117.400,000 2008 $ 118,100,000
Total charges, including capacity payments, under these contracts were approximately $181.0 million and $167.6 million for 2003 and 2002, respectively.
In the normal course of business Seminole has ongoing disputes with some of its power suppliers. During 2003, several disputes were settled resulting in refunds relating to purchased power costs recorded in prior periods totaling approximately $0.6 million, not including interest. This amount was recorded in 2003 as a reduction to purchased power expenses.
In October 2003, Energy Transfer Group, L.L.C., (ETG) a power marketer, filed suit against Seminole in the Circuit Court of the Twelfth Judicial Circuit in and for Manatee County, Florida, Case No. 2003-CA-5901. This case arises from a business arrangement between ETG and one of Seminole's members. ETG alleges contract interference and promissory estoppel on the part of Seminole and asserts that it enjoys the status of a third party beneficiary to the wholesale power contract between Seminole and its member. Seminole is vigorously contesting these allegations and believes that the resolution of this case will not result in a material adverse impact on Seminole's financial condition or its operations.
Seminole is a party to litigation involving various other claims arising in the normal course of business. In the opinion of management the ultimate resolution of these matters will not result in a material adverse impact on Seminole's financial condition or its operations.