ML021370512
| ML021370512 | |
| Person / Time | |
|---|---|
| Site: | Crystal River  |
| Issue date: | 05/02/2002 |
| From: | Bernhoft S Florida Power Corp |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| 3F0502-05 | |
| Download: ML021370512 (98) | |
Text
Is the Name of the Game
Tableof Contents 2
It's All in the Name: United States of America 4
We Stand by Our Name 6
Worthy of the Name 8
A Big Name in the Industry 10 Conservation Is Our Middle Name 12 Making a Name for Ourselves 14 You Name It, We Do It 16 Names You Can Rely On: OUC's Commissioners 18 Statistical Highlights 19 Our Numbers Strengthen Our Name 20 In a Competitive Game -
Every Player Counts A-1 Audited Financial Statements A-25 Independent Auditors' Report Pictured on cover (clockwise): Jeff Gustafson (Line Technician),
Debra Harvard (Customer Service Representative), Joe Yarborough (Technician),
Zoila Puig (Associate General Counsel), and John Gray (Manager, Water Quality Lab)
Pictured on page 2: Sam Smiling (Line Technician)
ouc Thc IfAWWRý,--5
Like other utilities across America, OUC quickly tightened access to its facilities and stepped upp other security measures in the aftermath of the tragic events of September 11, 2001.
We increased security at our water plants, power plants, substations and office buildings. We made sure that our key facilities were a top priority for local law enforcement patrols. And we instituted a litany of other security measures, such as reinforcing entrance gates at our properties and requiring all visitors to show picture ID upon arrival.
To us, these measures were reasonable and prudent, and employees and visitors have adjusted to the changes easily.
At OUC, the safety of our people and assets has always been of paramount importance. Our water plants are equipped with intrusion-detection systems, alarms, cameras and security fences around the perimeter of the properties. We also have limited employee access to facilities that are crucial to delivering electricity and water to our customers.
The threat of terrorism has created a new level of vigilance at OUC -
and we intend to stay at this new level. OUC is confident that its infrastructure for providing reliable service is safe and secure, and the company continues to explore new ways to enhance security while maintaining productive and comfortable working conditions.
2001 ANNUAL REPORT 3
C7mA I
Here at OUC, re4habiý ca 9
Always has beer, So in that respect, nothing changed at OUC -The Reliable One in fiscal year 2001. We're still delivering the most dependable electric and water services in the state of Florida. And, of course, we're still your hometown utility, where policy decisions are made by people who live in this community and who answer to its residents.
But in many other respects, last year was anything but routine at OUC. We won regulatory approvals for an exciting new power generation project with Southern Company, we rolled out even more products and services for our valued customers and, naturally, we stepped up security in the face of America's new terrorism threat.
As our customer base grew and demand for services increased, revenues hit an all-time high in fiscal 2001. Net income also increased, enabling us to set aside additional funds to prepare for deregulation while continuing our financial transfer to our owners, the City of Orlando.
We saw solid growth in OUCooling, our chilled water service for commercial air-conditioning systems, and in OUConvenient Lighting, the utility's lighting division. Meanwhile, we pressed forward with plans for even more offerings for our 168,000 customers. Among the soon-to-come services: residential lighting (decorative and security) and prepaid electric metering, which gives users greater control over their consumption while helping them conserve energy, too.
Speaking of conservation, OUC continued encouraging residents to use electricity and water more efficiently. Again faced with low rainfall levels, we spread the word about the need for protecting our all-important water resources -- and even implemented water conservation rates that provide incentives to use less.
Even as electric industry restructuring slowed in Florida, we worked diligently with other utilities and power marketers to solidify a federally mandated regional transmission organization.
Above all, last year saw OUC strengthen its core competencies while enhancing its customer service. For as long as anyone can remember, the utility's primary objective has been to deliver reliable, low-cost electric and water services. And we're accomplishing that and more.
The Reliable One is not just our name.
It's a driving force behind everything we do.
ROBERT C. HAVEN, P.E.
General Manager and CEO
Worthy WName Employees in every division of OUC help The keys to our success are many. For starters, OUC uses electric system equipment specifically designed to protect against lightning and handle Central Florida's other harsh weather conditions. Also, nearly 50 percent of our distribution system is underground, protecting it from trees and high wind.
1-00 7 ý' 1, !% \\
To further minimize outage time, EDBU fine-tuned its approach to scheduling personnel in fiscal 2001. The business unit now deploys multiple layers of response staff, including overnight trouble crews, to expedite power restoration.
In addition, OUC schedules a contingent of personnel who can be immediately redirected from performing routine work to resolve trouble calls. To increase the accuracy, speed and safety of these restorations, OUC has implemented mobile map access via laptop computer -
for its troubleshooting and operations staff.
Among the other reasons for OUC's dependability: proactive maintenance programs to identify and correct potential problems, proactive replacement of old equipment, and a tree-trimming program that minimizes tree-related service disruptions while maintaining a healthy, beautiful tree canopy.
"Above all, our talented and dedicated employees should take the credit for making us The Reliable One," says Ken Ksionek, Vice President of the Energy Delivery Business Unit.
At different points last year, we pushed the average annual customer interruption to below 32 minutes in Orlando and below 62 minutes in St. Cloud. While the numbers rose during the year's active storm season, OUC still maintained the solid reliability our customers have come to expect.
Another utility recently questioned OUC's reliability, so we commissioned an independent audit of our own data.
The results affirmed the excellence of our system performancp, as well as the way we document it, while also pointing to ways we can improve. As we move forward, OUC will continue to conduct systematic reviews of its performance, both internally and through the use of external auditors.
2001 also marked a historic milestone for the Energy Delivery Business Unit.
Formerly called the Electric Distribution Business Unit, the unit was renamed after merging with OUC's Electric Transmission Business Unit, which is being phased out with the anticipated creation of a regional, independent transmission organization.
EMIL KUNZ Chief Relay Technician
IlNa rne
- rid, Over the past year, OUC and its big-name partner -
Southern Company laid the groundwork for an important power generation project called Stanton A.
Site work for the 633 -megawatt unit considering recent layoffs in has already begun at OUCs Stanton the tourism industry and other Energy Center, with completion slated downward economic indicators.
for fall 2003. Aside from giving our C
community the additional juice it Plans call for Stanton A to be operational in fall 2003.
needs for the future, the natural gas-fired unit will feature the most efficient, environmentally advanced technology available.
A This is an exciting project that carries a substantial capital investment. It will create both good paying construction jobs and a number of permanent positions.
That's fantastic news for our community, 8 ORLANDO UTILITIES COMMISSION represents tne tnird pnase of OUC's comprehensive asset restructuring program. The program is aimed at diversifying and balancing OUC's mix of power generation resources to ensure "a competitively priced, reliable and environmentally clean asset base," says Fred Haddad, Vice President of OUC Power Resources.
PATTY WHITTAKER Administrative Specialist Stanton Energy Center The first phase of the program was selling our oldest power plant assets, the Indian River steam units.
The second phase was launching an Energy Risk Management Program that utilizes financial tools to hedge and stabilize fuel prices in the face of unprecedented market volatility.
"Our multifaceted strategy gives us the flexibility to maneuver in an uncertain energy market," Haddad says. "We've now reached a point where we're focused on fine-tuning our position and making adjustments to our strategy as the markets continue to move."
In our joint development partnership with Atlanta-based Southern Company, OUC will own nearly a third of the new generation unit's output. The Kissimmee Utility Authority and Florida Municipal Power Agency will each own 3.5 percent. Southern Company will own the remaining 65 percent.
Under an initial 10- year contract, OUC, KUA and FMPA will purchas all of Southern Company's generating capacity.
2001 ANNUAL REPORT 9 Green Power Turning Trash into Electricity AtoUC's Stanton Energy Center, methane gas from the nearby Orange County is used as fuel to erate e~lectricity. Each y this green power provides enough electricity for 10,000 "homes while reducing methane gas emissions from the landfill. The methane gas displaces more than 3 percent of the coal required for either Stanton Unit I or Unit II, saving OUC about $1.25 million a year in fuel costs.
A highlight of 2001 was seeing Stanton A make its way through the permitting process with relative ease, winning the approval of Governor Jeb Bush and his cabinet in September Regulating agencies focused on the unit's environmentally clean technology as well as the region's need for additional generation.
e The new unit will undoubtedly afford OUC even more stability, reliability and price protection in the future. And that means good things for retail customers -
our No. 1 priority -
and for our wholesale customers as well.
OUCOM
Conservation S
)
eu6/
d e Name
!otue%
As lower-than-normal rainfall levels continued, water conservation was the buzz in 2001.
Early in the year, the St. Johns River Water Management District handed down an order requiring utilities to reduce draws from the underground aquifer -e OnCs water source -
by 15 percent.
We quickly achieved that goal and then some.
Bolstered by a strong public relations push, OUC met with the city's largest commercial and residential customers to reduce water usage. In one case, we showed the Koger Center office complex in Orlando how to reduce its consumption by up to 75 percent and save millions of gallons a year.
Leading our face-to-face meetings with customers was OUC "conservation czar" Michael Malone, the utility's first full-time conservation coordinator.
ouc worked with Dudley Bates, General Manager of the Koger Center near consumption by up to 75 percent and reduce its utility bill.
OUC spread its "save water" message through bill inserts as well as television, radio and newspaper promotions. In addition, we implemented conservation rates that reward customers with lower rates as they use less water. The combined efforts were an unqualified success, with OUC water flows down more than 17 percent for the first nine months of 2001.
ORLANDO UTILITIES COMMISSION
Typically when water usage decreases, utilities have the tendency to increase rates to offset lower revenues. But despite the drop in OUC water flows, a general economic downturn and increases in the cost of water treatment supplies, the Water Business Unit shrunk overall operating expenses by 8 percent. Even better, OUC didn't have to raise rates.
"1 think our steady rates are a tribute to our department's monitoring of expenses," says Rob Hungate, OUC's Director of Water Production. "In every way, we made sure we were doing what was needed as efficiently as possible."
Orlando Fashion Square, to cut the business park's water "We have an obligation to reduce flows by as much as possible, and because of OUC's conservation efforts and other factors, we have achieved considerable success in that direction over the past year," says Rick Coleman, OUC's Director of Water Engineering and Technical Services.
Contributing to the Water Business Unit's healthy financial condition was the ongoing modernization of OUC's eight water treatment plants.
OUC's water professionals also developed new profit centers in 2001. For instance, our water treatment experts took a leading role in re-certifying water plant operators from around the region. Courses taught by OUC personnel have proven successful, not only creating a new revenue stream but i
also providing a useful networking opportunity for our team of experts.
MICHAEL MALONE Water Conservation Coordumtor
Making a Name Ourselves OUC further expanded its product and service offerings to provide more convenience to customers last year.
display unit for We also implemented Inew programs to help people save energy, water and money.
On the residential side, we greatly extended the reach of our free home energy audits. OUC traditionally has sent auditors into the field to show residents how to maximize the energy and water efficiency of their homes.
While we still provide that service, we now also offer an OUC home energy audit online (www.ouc.com) as well as in videotape and CD-ROM formats.
"Customers can simply go to their desktop computers for the same level of information they would get from meeting with one of our auditors,"
says Doug Spencer, Vice President of the OUCustomer Connection.
In the works are other money-saving programs.
In fact, a test group of customers is already using the utility's new prepaid electric metering program branded OUCash Control. The system gives customers greater control over their energy consumption and enables them to monitor their usage.
In areas of the country where prepaid metering is common, users have been able to cut their consumption by 10 to 15 percent. We expect to see similar results.
12 ORLANDO UTILITIES COMMISSION
At the Citrus Bowl, OUConvenient Lighting has increased the stadium's brightness while reducing its energy costs.
stadium's old field lights with higher-output, energy-efficient lights. In fact, we installed half as many fixtures as before and still increased the stadium's brightness -
while reducing energy costs.
Also last year, OUC inaugurated its Lighting Retrofit Program for commercial customers.
Under the program, we are retrofitting customers' indoor lighting systems with more energy-efficient, cost-effective systems.
Energy savings are projected in the 65 to 70 percent range.
We're also planning to roll out a residential lighting program under the OUConvenient Lighting banner We will offer a variety of decorative and security lighting fixtures and even provide installation -
all at competitive prices and with the rock-solid reliability people have come to expect from OUC.
Speaking of OUConvenient Lighting, the commercial side of that business attracted considerably more attention last year from office parks, sports complexes and other developments. For instance, under a new 10-year contract with the City of Orlando, the lighting division began providing complete installation and maintenance of the Citrus Bowl's field lighting. We replaced the In return for the new lights, customers are reimbursing OUC with the money they save until the equipment is paid off, which usually takes just three to four years.
Our chilled water service for commercial air-conditioning systems, OUCooling, continued to expand its horizons in fiscal 2001.
Through its contract with the Orange County Convention Center and VALERIE AMILIBIA Customer Service Analyst a new arrangement with nearby Lockheed Martin, OUCooling is poised to offer its low-cost, hassle-free service to a number of hotels and other properties along tourist-heavy International Drive.
Additionally, OUCooling is serving the Sheraton Vistana Villages timeshare complex in south Orange County and will begin serving the upscale Mall at Millenia in October 2002. The chilled water business, with nine customers linked to its south downtown Orlando "loop," is also casting an eye toward a similar project on the north side of downtown.
DAVE SAILER OUCoohng Operations Coordinator O
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ý TRIGENIiNEDCY SOLUTIONS S-ý 2001 ANNUAL REPORT 13
You Name We D It It 0
Marketing, Communications
& Community Relations When it comes to community involvement, OUC has energy to burn. Employees at all levels of the company participate in charitable activities, serve on non-profit boards and contribute their time and money to good causes.
In the aftermath of the terror attacks in New York and Washington, D.C., OUC employees donated more than $20,000 to the September 11 th Fund. The utility matched employee contributions -
plus nearly $2,400 donated by students at downtown Orlando's Passport Charter School -
bringing OUC's total contribution to more than $45,000.
OUC's community involvement is one of the many responsibilities of Marketing, Communications & Community Relations (MCCR).
Among the department's other duties: advertising, public information, media relations and office services.
While it concentrated on promoting conservation (energy and water) in fiscal 2001, MCCR also spread the word about OUCooling, OUConvenient Lighting and the utility's many other products and services.
OUC informs its customers through a variety of printed materials, videos and CD-ROMs.
"We create a comprehensive marketing plan for every one of our services," says Roseann Harrington, Vice President of MCCR.
"Our strategy is aimed at generating immediate and long-term interest in OUC services while continually strengthening our brand as The Reliable One."
Information Technology Our newly restructured Information Technology division, under the direction of Chief Information Officer Tom Washburn, had a busy first year. By the end of fiscal 2001, some 40 IT initiatives were under review by our Technical Prioritization Committee, which ensures that projects are developed with an eye toward company-wide integration.
IT is making sure all new systems can exchange data or "talk to" other systems. For instance, power outage information collected by our new Energy Management System soon will be linked to the customer trouble call data collected by our Outage Management System. This will speed the process of restoring power and notifying customers of restoration status.
.4 14 i ORLANDO UTILITIES COMMISSION
2001 was a year of system enhancements at OUC. Upgrades were made to STORMS, the project management software used by electric and water engineering departments, as well as to our JD Edwards OneWorld program, which handles business and accounting tasks. We also made improve ments to our Customer Information System (CIS), which collects meter readings and processes bills. To achieve more bill processing flexibility, we began sending bill data to ComTech, a vendor that provides bill printing and mailing.
This improved the Corporate Services After a year of intensive evaluation and reorganization, Corporate Services is seeing its efforts pay off. For example, streamlining the Purchasing and Materials Management divisions into a single division, Supply Chain Management, has already led to more efficiencies and t
lower costs.
Corporate Services supports all areas of OUC, providing everything from human resources and environmental engineering to safety and security. "As pillars of this organization, our job is to stand behind the scene Oib and make sure the curtain opens and closes properly, not to stand out front and take the bows,'
says Al Frazier, Vice President of Corporate Services.
The business unit continues to forge new vendor partnerships and expand existing ones to outsource costly functions and reduce standing inventories. Last year alone, OUC's new lease arrangement with Wesco enabled us to remove more than $2 million in standing electric transformer stocks. In another example, our new automotive parts partnership with NAPA reduced operating costs by $220,000 in fiscal 2001.
However, not all savings are created through outsourcing.
We brought tool and equipment repair in house, which resulted in savings of nearly 75 percent over the use of outside vendors. Other achievements last year include a 14 percent increase in OUC's utilization of minority-and women-owned business vendors and the installation of new energy conservation lighting at OUC facilities. Perhaps most important of all, OUC reached a major safety milestone, completing more than 1.4 million work hours without an injury requiring time away from the job.
"The success of Corporate Services is measured by how effectively the entire organization performs its job," Frazier says.
2001 ANNUAL REPORT 115
RAY D. McCLEESE First Vice President THE HONORABLE GLENDA HOOD Mayor -
Commissioner
Statistical Highlights (Dollars in Thousands)
% Increase For Years Ended Sept. 30 2001 2000 (Decrease) 1991 COMBINED OPERATIONS Operating Revenues 536,594 501,131 7.1%
309,452 Total Operating Expenses 446,564 407,979 9.5%
226,136 Interest and Other Income 52,223 50,703 3.0%
30,954 Interest and Other Expenses 88,768 92,548
-4.1%
84,181 Net Income 53,485 51,307 4.2%
30,089 Payments to City of Orlando 48,046 45,116 6.5%
28.200 Utility Plant (Net book value) 1,538,156 1,512,663 1.7%
1,024,585 Equity 619,783 598,431 3.6%
360,126 Long-term Debt 1,367,949 1,388,343
-1.5%
1,108,788 Total Assets 2,411,327 2,366,211 1.9%
1,605,308 Debt Service Coverage:
Senior lien 4.34 4.17 4.1%
2.68 Junior lien 3.84 3.63 5.8%
4.63 Combined debt 2.17 2.07 4.8%
1.88 Senior Bond Ratings (1)
AA,Aal,AA AA,Aal,AA AAA,Aal,AA ELECTRIC BUSINESS UNIT Operating Revenues 497,597 454,236 9.5%
289,962 Total Operating Expenses 415,775 377,143 10.2%
209,997 Fuel and Purchased Power 231,128 204,656 12.9%
103,233 Departmental Operations (2) 184,647 172,487 7.0%
106,764 Total Sales (MWH) 7,633,910 7,335,720 4.1%
5,115,557 Total Retail Sales (MWH) 4,846,894 4,666,110 3.9%
3,546,436 Commercial/Industrial Sales 3,199,999 3,094,065 3.4%
2,339,469 Residential Sales 1,646,895 1,572,045 4.8%
1,206,967 Sales for Resales (MWH) 2,787,016 2,669,610 4.4%
1,569,121 Total Active Services (3) 149,735 146,765 2.0%
118,273 Residential 129,342 126,776 2.0%
102,033 Commercial/Industrial 20,393 19,989 2.0%
16,240 Average Annual Residential Use (KWH) 12,860 12,657 1.6%
11,829 Average Revenue per KWH Residential Sales 8.14¢ 7.84¢ 3.8%
7.56¢ Heating Degree Days 706 452 56.2%
304 Cooling Degree Days 3,278 3,389
-3.3%
3,875 Gross Peak Demand (MW) 1,030 1,028 0.2%
779 WATER BUSINESS UNIT Operating Revenues 38,997 Total Operating Expenses 30,789 Sales (In Thousands of Gallons) 29,305,811 Total Active Services 119,197 Residential 95,254 Commercial/Industrial 11,351 Irrigation 12,592 Average Annual Residential Customer Usage (Gal.)
159,000 Average Revenue per 1,000 gallons Residential Sales (Dollars Not in Thousands) $
1.41 Rainfall (inches) 52.0 Peak Pumping (Million Gallons per Day) 111.7 46,895 30,836 33,185,930 117,935 94,643 11,190 12,102 180,000 1.49 39.6 181.1
-16.8%
-0.2%
-11.7%
1.1%
0.6%
1.4%
4.0%
-11.7%
-5.4%
31.4%
-38.3%
19,490 16,139 24,498,992 100,352 84,276 10,073 6,003 151,000 83.531 59.6 125.7
- 1.
Bond Rating Agencies: Fitch Investors Service Inc., Moody's Investors Service, and Standard & Poor's, respectively.
- 2.
All expenses less fuel and purchased power.
- 3.
Total Active Services represents all metered services exclusive of St. Cloud, Florida.
18a ORLANDO UTILITIES COMMISSION
Our"Numbers Strengthen Our Name OUC enjoyed another strong financial year in fiscal 2001. Operating revenues rose 7.1 percent to $536.6 million. Net income hit $53.5 million.
Thanks to our highly reliable power generation resources, we served our retail electric customers while also meeting the steady demand for power on the wholesale market. In fact, wholesale electric sales exceeded budget by 32 percent.
Higher prices for the fuel used to generate electricity forced OUC to increase its customer fuel charge in October 2000. A second increase followed in May 2001, the first mid-year fuel increase since 1987.
Thanks to the fuel diversity of our power generation mix and support from our fuel stabilization ANGELA JOHNSON fund, OUC's increases were lower than those Senior Accountant of other Florida utilities. Throughout the year, OUC residential electric customers paid between 10 percent and 14 percent less than customers of our nearest competitor.
On the water side, consumption dropped 12 percent to 29.3 billion gallons in fiscal 2001. For the first nine months of calendar year 2001, consumption dropped by more than 17 percent. This was the result of several factors, including a strong public relations campaign urging conservation, new OUC water conservation rates and mandatory watering restrictions set by the region's water management districts.
OUC's financial strength allowed us to transfer
$32.1 million to the City of Orlando to help pay for police and fire services, parks and playgrounds, and other important community services.
In affirming OUC's AA bond rating, credit agency Fitch cited the utility's "solid financial performance, low-cost generating resources, competitive retail rates and growing service territory." Moody's Investors Service and Standard
& Poor's also assigned excellent ratings to OUC bonds -
Aa1 and AA, respectively.
"OUC's continued financial strength is our primary objective," Vice President and Chief Financial Officer John Hearn says.
8 7
5 2
0 3S 30 25 20 is 0
Total Electric Sales (In Millions of Megawatt Hours)
Total Water Sales (In Billions of Gallons)
Soo Soo 400 200 2 0 0 1 9 9 1 Total Operating Revenues (In Millions of Doliars)
Soo Soo 400 2001 1991 Total Operating Expenses (in Millions of Dollars) s0 so 40 30 20 10 01 2001 19 Net Income (in Millions of Dollars) 2001 ANNUAL REPORT 119
Orlando Utilities Commission September 30, 2001 and 2000 Audited Financial Statements Commission Members & Officers Tico Perez
)%udso(
Ray D. McCleese Fist Tice President Tommy Boroughs S*soud Vice% sidnt Carol P. Wilson, Ph.D.
Immediate Past Pesoidva Glenda E. Hood Mayor-Comissioonr Robert C. Haven, RE.
Secaet.y John E. Hearn Betty J. Perrow Sharon L Knudsen A,,ssitat Secrdtari Management Robert C. Haven, RE.
General Manager and Cnif Ear,,Iie a
/,, rI Alvin C. Frazier Viee Prouden Frederick F. Haddad, Jr.
lce President Power Resources Bussesss Unit Roseann E. Harrington Vic, Preidden Mad&e*si*
Cnomkuunealos
& Commrds Reltions John E. Hearn Viae P dednt
.. d C*,if F inansi Officer Fsosondat Services Kenneth P. Ksionek VFe Presiden Energy Delivery Busiesks Usit Douglas M. Spencer Vue P.sident OUs0mCesro Csososoi Thomas B. Tart, Esq.
Vice Biesident and Gseaml Comse Thomas E. Washburn F,*e Presidret T7anosmsiosn Bhusiness E *nit sod Chief hfonnation Officer Contents A-2 Balance Sheets A-4 Statements of Revenues, Expenses and Changes in Retained Earnings A-5 Statements of Cash Flows A-6 Notes to Financial Statements A-25 Independent Auditors' Report 2001 ANNUAL REPORT A-1
Balance Sheets ASSETS September 30 (Dollars in Thousands) 2001 2000 Utility Plant In Service:
Electric...
$1,681,407
$1,626,201 Water.....
332,097 311,621 Common.....
133,535 125,918 Allowances for depreciation and amortization (deduction)
(672,077)
(594,383) 1,474,962 1,469,357 Donated Utility Plant (Net)......
(8,243)
Construction work in progress..........................................
71,437 43,306 Total Utility Plant (Net)...............................................
1,538,156 1,512,663 Restricted and Internally Designated Assets Debt service and related funds.....
177,379 176,603 Renewal and replacement fund.....
47,522 47,883 Construction and related funds............................................
24,557 61,898 Customer meter deposits............................................
15,008 13,420 Total restricted assets 264,466 299,804 Liability reduction fund......
328,917 307,422 Stabilization funds.......
73,024 43,757 Self-insurance fund......
4,527 4,589 Total internally designated assets......................................
406,468 355,768 Total Restricted and Designated Assets................................
670,934 655,572 Current Assets Cash and investments..................................................
55,294 39,097 Customer accounts receivable, less allowance for doubtful accounts (2001 -
$1,518, 2000 -
$2,036)................................
58,243 70,497 Accrued utility revenue..................................................
23,668 21,826 Fuel for generation.......
4,716 3,650 Materials and supplies inventory...........................................
26,342 26,603 Accrued interest receivable.......
2,700 8,271 Miscellaneous receivables and prepaid expenses...........................
19,142 17,167 Total Current Assets.....
190,105 187,111 Other Assets Deferred interest expense......
8,569 8,977 Unamortized debt issuance costs 2,079 1,888 Other deferred costs................................................
1,484 Total Other Assets................................................
Total Assets..
See notes to the financial statements.
12,132
$2,411,327 10,865
$2,366,211 A-2, ORLANDO UTILITIES COMMISSION
CAPITALIZATION September 30 (Dollars in Thousands) 2001 2000 Equity Retained earnings:
Reserved for debt service.............................................
$114,294
$114,039 Reserved for renewal and replacement......................................
47,522 47,883 Unreserved -
invested in or designated for plant and working capital 323,401 297,867 Total Retained Earnings.....
485,217 459,789 Contributed Capital................................................
134,566 138,642 Total Equity.........................................................
619,783 598,431 Long-Term Debt Bond and note principal................................................
1,475,100 1,501,385 Unamortized discount and deferred amount on refunding......................
(107,151)
(113,042)
Total Long-Term Debt (Net)............................................
1,367,949 1,388,343 Total Capitalization....................................................
1,987,732 1,986,774 LIABILITIES Current Liabilities -
payable from restricted assets Accrued interest payable on notes and bonds..............................
34,254 36,520 Current portion of long-term debt.......................................
54,190 38,336 Customer meter deposits 15,008 13,420 Total Current Liabilities from Restricted Assets.........................
103,452 88,276 Current Liabilities -
payable from current assets Accounts payable and accrued expenses....................................
55,294 45,820 Billings on behalf of state and local governments...............................
.9,931 9,937 Accrued payments to the City of Orlando.................................
8,516 8,373 Total Current Liabilities 73,741 64,130 Other Liabilities and Deferred Credits Deferred gain on sale of assets....
123,437 135,203 Deferred revenue.....
121,043 90,089 Water and electric construction deposits and other..........................
1,922 1,739 Total Other Liabilities and Deferred Credits.............................
Total Liabilities....................................................
Total Capitalization and Liabilities.....................................
See notes to the financial statements.
246,402 423,595
$2,411,327 227,031 379,437
$2,366,211 2001 ANNUAL REPORT! A-3
Statements of Revenues, Expenses and Changes in Retained Earnings REVENUES AND EXPENSES Year Ended September 30 (Dollars in Thousands) 2001 2000 Operating Revenues:
Electric retail...
$326,094
$304,321 Electric resale.....
159,998 138,793 Water revenues......
38,997 46,895 Other revenues.....
11,505 11,122 Total Operating Revenues....
536,594 501,131 Operating Expenses:
Fuel for generation and purchased power....................................
231,128 204,656 Unit/Department expenses..............................................
108,710 107,167 Depreciation and amortization.........................................
77,248 68,558 Payments to other governments and taxes....................................
29,478 27,598 Total Operating Expenses...............................................
446,564 407,979 Operating Income.....
90,030 93,152 Non-Operating Income:
Interest income......
41,045 40,986 Amortization of deferred gain on sale of assets............................
11,178 9,717 Interest expense and other.....
(88,768)
(92,548)
Net Incom e Retained earnings at beginning of year....................................
Dividends to the City of Orlando.........................................
Depreciation on donated utility plant and contributed capital.....................
Accumulated Retained Earnings at End of Year............................
See notes to the financial statements.
53,485 459,789 (32,091) 4,034
$485,217 51,307 435,528 (30,784) 3,738
$459,789 A-4A ORLANDO UTILITIES COMMISSION
Statements of Cash Flows CASH FLOWS (Dollars in Thous'ands )
Cash Flows from Operating Activities Operating Income Adjustments to reconcile operating income to net cash provided by operating activities:
Depreciation and amortization of plant charged to operations.................
Depreciation and amortization charged to fuel for generation and purchased power.................................
Depreciation of vehicles and equipment charged to Unit/Department expenses Changes in Operating Assets and Liabilities:
Decrease/(Increase) in receivables and accrued revenue......................
(Increase)/Decrease in fuel and materials and supplies inventories...............
Increase in accounts payable and accruals...............................
(Decrease) in deposits payable and deferred items..........................
Increase in stabilization and deferred revenue accounts.......................
Year Ended September 30 2001 2000
$90,030 77,248 3,299 1,453 10,412 (805) 8,930 (2,608) 26.057
$93,152 68,558 3,330 1,090 (11,719) 8,174 9,852 (4,389) 24.417 Net Cash Provided by Operating Activities...............................
214,016 192,465 Cash Flows from Non-Capital Financing Activities Dividend payment to the City of Orlando..................................
(31,984)
(32,088)
Net Cash Used In Non-capital Financing Activities.........................
(31,984)
(32,088)
Cash Flows from Capital and Related Financing Activities Debt interest payments.....
(76,198)
(78,486)
Principal payments on long-term debt........................................
(61,735)
(41,088)
Debt issuances......
50,290 6,400 Debt issuances expenses paid.............................................
(2,795)
(467)
Construction and acquisition of utility plant net of donated utility plant and contributed capital.......................................
(103,664)
(76,482)
Proceeds relating to sale of Indian River steam units.........................
187,995 Net Cash Used In Capital and Related Financing Activities...................
(194,102)
(2,128)
Cash Flows from Investing Activities Proceeds from sales and maturities of investment securities.....................
677,945 323,146 Purchases of investment securities........................................
(607,209)
(603,858)
Investment income.....
46,065 35,047 Net Cash Provided by (used In) Investing Activities........................
Increase/(Decrease) in Cash and Cash Equivalents...........................
Cash and Cash Equivalents at Beginning of Year..............................
Cash and Cash Equivalents at End of Year...............................
See notes to the financial statements.
116,801 104,731 54,305
$159,036 (245,665)
(87,416) 141,721
$54,305 2001 ANNUAL REPORT A-5 Mollars in Thousan
Notes to Financial Statements (1)ollars in Thousands)
NOTE A -
THE ORGANIZATION Orlando Utilities Commission (OUC) was created in 1923 by a Special Act of the Florida Legislature as a statutory commission of the State of Florida. The Act confers upon OUC the rights and powers to fix rates and charges for electric and water services. OUC is responsible for the acquisition, generation, transmission and distribution of electric and water services to its customers within Orange and Osceola Counties.
OUC's governing board consists of five members including the Mayor of the City of Orlando. Members serve without compensation and with the exception of the Mayor, who is an ex-officio member of OUC, may serve no more than two consecutive four-year terms.
NOTE B -
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES Reporting Entity: OUC meets the criteria of an "other stand-alone government" as defined in Statement 14 of the Governmental Standards Board, The Financial Reporting Entity. No component unit exists as defined by Statement 14; however, OUC has undivided interests in a number of power plants through participation agreements as described in Note C. Under these arrangements, the title to the property is held in proportion to each party's interest, and each party is obligated for its share of operations. There are no separate entities or organizations associated with the agreements.
Basis of Presentation: The financial statements of OUC are presented in conformity with generally accepted accounting principles for enterprise funds as prescribed by the Governmental Accounting Standards Board (GASB) and where not in conflict with GASB pronouncements, accounting principles prescribed by the Financial Accounting Standards Board (FASB). The accounting records are maintained substantially in accordance with the accounting principles and methods prescribed by the Federal Energy Regulatory Commission (FERC) except for the depreciation of donated utility plant and contributed capital which is excluded from the determination of net income.
OUC is a regulated enterprise and, as such, applies the accounting principles permitted by Statement of Financial Accounting Standards No. 71 -
Accounting for the Effects of Certain Types of Regulation (SFAS 71). Under SFAS 71, certain expenses and revenues are deferred and recognized in accordance with rate actions of OUC's governing board.
OUC has elected not to apply FASB statements and interpretations issued after November 30, 1989, as permitted by Statement No. 20 of the Governmental Accounting Standards Board, Accounting and Financial Reporting for Proprietary Funds and other Governmental Entities that use Proprietary Fund Accounting.
Certain amounts for 2000 have been reclassified to conform with the 2001 presentation.
Budgets: Revenue and expense budgets are prepared on an annual basis in accordance with OUC's budget policy and bond resolutions and submitted to OUC for approval prior to October 1 of the fiscal year. Legal adoption of budgets is not required. Actual revenues and expenses are compared to the budgets on a line item basis within departments, and an analysis of variances report is prepared and submitted to OUC each month as required by OUC's budget policy and bond resolutions.
Utility Plant: Utility plant is stated at historical cost. These costs include the costs of contract work, labor, materials and allocated indirect charges for equipment, supervision and engineering less development fees received from residential and commercial customers. Depreciation is recorded systematically using the straight line method over the estimated useful life of 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 is recorded as a gain (loss) on disposition of property unless regulatory action is taken by the governing board.
Ae61 ORLANDO UTILITIES COMMISSION
(Dollars in Thousands)
NOTE B -
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES (continued)
The balances of utility plant in service at September 30 are listed below with a range of depreciable lives for each:
UTILITY PLANT (Net)
September 30 2001 2000 Electric Power generation (5-40 years)..........................................
$1,012,858
$ 997,294 Transmission (5-30 years).....................
160,817 228,984 Distribution (5-50 years).....
498,051 401,110 Water (3-50 years).......................................................
339,337 320,237 Chilled water (20-40 years).................................................
27,460 24,504 Shared/customer services (3-50 years)....................................
108,516 91,611 Total utility plant......................................................
2,147,039 2,063,740 Accumulated depreciation....
(661,481)
(575,099)
Allowance for decommissioning..........................................
(10,596)
(19,284)
Net utility plant before donations...........................................
1,474,962 1,469,357 Donated utility plant (net)...............................................
(8,243)
Construction work in progress 71,437 43,306 Total net utility plant
$1,538,156
$ 1,512,663 Nuclear Decommissioning Costs: OUC funds nuclear decommissioning costs on an annual basis in accordance with the estimates included in the Florida Public Service Commission (FPSC) dockets # 941352-El issued in 1995 for both St. Lucie and Crystal River and #991931 issued in 2001 for Crystal River. A trust fund has been established to provide certain financial assurances that funds will be available when needed for required decommissioning activities. The annual funding for each trust fund is calculated based on an estimated earnings rate of 5.75%, expected over the life of the trust. The total obligation, as approved by the FPSC, is not presented on the balance sheet as it is intended to be recognized, based on earnings, over the life of the facility. Estimated costs of decommissioning are periodically adjusted in response to requirements of the FPSC and the Nuclear Regulatory Commission (NRC).
The following amounts represent the total obligation, the amount recorded on the balance sheets (the funded amount) and the future funding requirements as of September 30:
September 30 2001 2000 St. Lucie Unit No. 2 Total obligation....
$ 22,495*
$ 22,495*
Funded amount........................................................
17,267 14,327 Future funding requirements...........................................
5,228 8,168 Crystal River Unit No. 3 Total obligation......
8,260**
6,480*
Funded amount.......
5,478 4,777 Future funding requirements............................................
$ 2,782 1,703
- In 1995 dollars.
In 2000 dollars.
Cash, Cash Equivalents & Investments: Cash equivalents include all 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, is presented at the share price.
2001 ANNUAL REPORT A-7
(Dollars in 7Thousands)
NOTE B -
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES (continued)
Investments are reported at fair market value with the exception of the funds held in the Debt Service Reserve funds. The Debt Service Reserve funds, in accordance with OUC's ratemaking model, are recorded at amortized cost and at September 30, 2001 and 2000 had a fair market value in excess of amortized costs of $8,021 and $2,852, respectively. This treatment is consistent with OUC's intent and ability to hold these investments to maturity. Other fund realized and unrealized gains and losses are included in interest income in the statements of income. Premiums and discounts on bonds and other investments are amortized using the effective interest method.
OUC is authorized to invest in the Surplus Funds Investment Pool Trust Fund administered by the State Board of Administration of Florida, obligations of the United States Treasury and its various agencies, interest-bearing time certificates of deposit, repurchase agreements, reverse repurchase agreements, state and local government obligations, bankers' acceptances and prime commercial paper.
A repurchase agreement is a secured transaction occurring between OUC and a primary securities dealer. OUC will exchange cash for temporary ownership of specified collateral with an agreed upon rate of interest and maturity. Specified collateral is limited to direct governmental and agency obligations with terms of ten 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. If a securities dealer were to default, OUC could experience an economic loss equal to the difference in the market value plus the accrued interest of the underlying securities (collateral) and the repurchase agreement value including accrued interest.
Energy Risk Management and Derivative Instruments: Derivative transactions are executed in accordance with OUC's internally established Energy Risk Management Oversight Committee (ERMOC) of which the primary objective is to minimize exposure to energy price volatility for cash flow and control purposes. The Committee has a defined organizational structure and responsibilities, which include approving all brokerage relationships, counter-party creditworthiness, and overall program compliance. In addition, the Energy Risk Management Program was established with specific volume and financial limits which are 20% of the annual fuel budget and
$30,000, respectively.
In accounting for fuel hedge activities, OUC records these derivative instruments on the balance sheet as either an asset or liability measured at fair market value. Related gains and/or losses on transactions are deferred and recognized in the specific period in which the instrument was hedged and are included as a part of fuel and purchase power costs. At September 30, 2001, OUC has derivative instruments (swaps, futures and optionsl with a net fair market value of $1,700.
Customer Accounts Receivable and Unbllied Revenues: OUC bills customers monthly on a cyclical basis and accrues revenues at the end of the fiscal year for electric and water consumed but not billed. See "Rates and Revenues" below, The customer accounts receivable balance of $58,243 and $70,497 at September 30, 2001 and 2000, respectively, includes billings on behalf of state and other local governments. The net liability of $9,931 and $9,937 at September 30, 2001 and 2000, respectively, (billings on behalf of state and local governments less expenses) represents the September billings of these governments.
Fuel for Generation and Materials and Supplies Inventory: Fuel oil, coal and materials and supplies inventories are stated at their average cost. Nuclear fuel is included in electric utility plant and amortized to fuel expense as it is used.
Unamortized Debt Issuance Cost: Unamortized debt issuance costs represent issuance costs related to bond issuances which are amortized using the bonds outstanding method and recorded net of accumulated amortization.
Interest Rate Swap Agreements: OUC enters into interest rate swap agreements to modify interest rates on outstanding debt.
Other than the effect on total interest from those agreements, no fair market value amounts related to these agreements are recorded on the financial statements.
A-81 ORLANDO UTILITIES COMMISSION
(Dollars in Trhousands)
NOTE B -
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES (continued)
Unamortized Discount and Deferred Amount on Refunding: Unamortized discount on outstanding bonds is amortized using the bonds outstanding method and is recorded net of accumulated amortization. Deferred amounts on refunding represent deferred losses from bond refundings. These amounts are amortized over the shorter of the lives of the refunded debt or refunding debt using the straight-line method and are recorded net of accumulated amortization.
Compensated Absences: OUC records compensation for unused vacation and sick leave as an expense in the year in which the vacation and sick leave is earned In accordance with the GASB Statement No. 16, Accounting for Compensated Absences. At September 30, 2001 and 2000, annual vacation leave earned but not taken was $769 and $693; sick leave accumulated but not taken was $2,666 and $2,591, respectively, Such amounts are included in the balance sheets under the caption, Accounts payable and accrued expenses.
Rates and Revenues: Each year, OUC's staff performs a rate adequacy study to determine the electric and water revenue requirements. Based on this study, current cost of service studies, and regulations of the Florida Public Service Commission regarding electric "rate structure," OUC's staff develops its electric and water rate schedules which are presented at a public workshop and then presented for approval at a subsequent meeting of the governing board.
OUC staff makes its determination of revenue requirements using the cost of service rate base method and includes construction work in progress in the rate base. Therefore, in accordance with proper ratemaking theory, OUC does not use an allowance for funds used during construction (AFUDC) in determining revenue requirements. Since OUO's level of revenue requirements and subsequent revenue is determined without regard to AFUDOC, OUC does not capitalize interest on construction work in progress for electric and water projects on which rates are based.
Operating revenues are recorded based on actual billings to customers plus an estimate for accrued unbilled electric and water consumption at the end of each fiscal year.
Recent Accounting Pronouncements: The GASB has issued three (3) new pronouncements which are as follows:
"* Statement of Governmental Accounting Standards (SGAS) No. 33, Accounting and Financial Reporting for Non-Exchange Transactions.
"* Statement of Governmental Accounting Standards (SGAS) No. 34, Basic Financial Statements and Management's Discussion and Analysis for State and Local Governments.
"* Statement of Governmental Accounting Standards (SGAS) No. 36, Recipient Reporting for Certain Shared Non-Exchange Revenues -
an amendment of GASB No. 33, Accounting and Financial Reporting for Non-Exchange Transactions.
In conjunction with OUO's adoption of SGAS No. 33 and 36, and the application of SFAS 71, effective October 1, 2000, customer contributions received in fiscal year 2001, have been recorded as donated utility plant. Prior year customer contributions have been reported as a part of equity. This treatment Is consistent with OUC's rate-making model and industry standards. There is no material financial impact related to this change.
OUC plans to adopt SGAS No. 34 -
a fundamentally new financial reporting model for all state and local governments including management's discussion and analysis of OUC's financial position and result of operations -
in 2002 in accordance with the implementation requirements in the accounting standard. OUC does not believe the implementation of SGAS No. 34 will materially impact its financial position or results of operations.
2001 ANNUAL REPORT IA-9
(Dollars in Thousands)
NOTE C -
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, 2001 and 2000 and are as follows:
Total FMPA KUA Net OUC Facility Net Undivided Undivided Undivided Agreement Megawatt Ownership Ownership Ownership Facility Name Year Capacity interest Interest Interest Stanton Unit No. I (SEC1) 1984 & 1985 440 26.6265%
4.8193%
68.5542%
Stanton Unit No. 2 (SEC2) 1991 440 28.4091%
71.5909%
Indian River Combustion Turbines (A&8) 1988 96 39.0000%
12.2000%
48.8000%
Indian River Combustion Turbines (C&D) 1990 236 21.0000%
79.0000%
OUC operates a wastewater treatment facility at the SECI and SEC2 site through an agreement with Orange County. In the prior year, Orange County shared a portion of these operating costs with OUC resulting in a reduction of operating and maintenance expenses to OUC of $879 in 2000. Effective October 2000, Orange County no longer shared a portion of these operating costs.
Non-OUC Operated: OUC maintains an undivided participant interest with Florida Power & Light at their St. Lucie Unit No. 2 nuclear generation facility, with Florida Power at their Crystal River Unit 3 nuclear generation facility and with the City of Lakeland at their McIntosh Unit 3 coal-fired generation facility. In each of these agreements fiscal, budgetary and operational control is 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 currently being constructed. The total facility is expected to have a net megawatt capacity of 633 of which OUC's undivided share will be 28% or approximately 177 units of net megawatt capacity.
These agreements and the related ownership, with the exception of Stanton A which began construction this year, have remained consistent for the years ending September 30, 2001 and 2000 and are as follows:
Total OUC Facility Net Undivided Net OUC Agreement Megawatt Ownership Megawatt Facility Name Year Capacity Interest Capacity 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 1.6020%
13 Stanton A (SECA) 2001 633 28,0000%
177 Plant balances and construction in progress for SECl, SEC2, SECA, MAC3 and the IRP CT's 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. Allowance for depreciation and amortization of utility plant in service is determined by each participant based on their depreciation methods and rates relating to their share of the plant. During fiscal years 2001 and 2000, OUC authorized an additional
$10,600 and $2,900, respectively, in depreciation of its interest in the SL2 nuclear generating plant.
A-1ie ORLANDO UTILITIES COMMISSION
(Dollars in T'1housands)
NOTE C -
JOINTLY OWNED OPERATIONS (continued)
The following is a summary of OUC's recorded net share of each jointly owned plant:
September 30 2001 2000 Stanton Energy Center Unit No. 1.........................................
$197,221
$ 202,750 Stanton Energy Center Unit No. 2.........................................
313,176 320,525 McIntosh Unit No. 3......
62,387 65,420 Indian River Combustion Turbines.....
44,125 38,558 St. Lucie Unit No. 2......
22,967 36,619 Stanton Energy Center Unit A.............................................
13,613 Crystal River Unit N6. 3.................................................
(1,876)
(1,440)
Total
$ 651,613
$ 662,432 NOTE D -
CASH, CASH EQUIVALENTS, AND INVESTMENTS OUC's cash deposits are held in institutions insured by the Federal Deposit Insurance Corporation or collateralized by a pool of U.S. Governmental securities held in trust by a third party bank in the name of OUC's banking institution. 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 m
money market funds
- commercial paper
- certificates of deposit Investments in commercial paper must be rated "A-1", "P-1", or its equivalent. OUC's investments in money market funds are limited to funds which meet the Securities and Exchange Commission definition of a fund that seeks to maintain a stable net asset value of
$1 per share and is rated not less than Aaa, AAAm or an equivalent rating by at least one nationally recognized rating service.
OUC invests funds with the Local Government Surplus Funds Investment Pool Trust Fund (the "Surplus Funds Investment 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 1.0% and 3.0% of the Surplus Funds Investment Pool portfolio at September 30, 2001 and 2000, respectively. These investments derive their value from certain floating rate notes based on the prime rate and/or one and three month London Interbank 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, the investment committee considers the risk of loss of principal to be remote.
2001 ANNUAL REPORTIA-11
(Dollars in Thousands)
NOTE D -
CASH, CASH EQUIVALENTS, AND INVESTMENTS (continued)
The following are the cash, cash equivalents and investment deposits held by OUC at September 30, 2001 and 2000, respectively:
September 30 CASH & CASH EQUIVALENTS 2001 2000 Cash
$114,689
$ 52,361 Investments - Category I (Insured or Registered & Held by OUC or Agent in OUC's Name):
Repurchase agreements.......
11,022 7,000 U.S. government securities.............................................
167,442 259,592 Other U.S. and agency backed securities..................................
421,101 361,728 Total Category 1 investments....
599,565 628,320 Investments - Category 2 (Uninsured & unregistered and held by banks trust or agent in OUC's name):............
Investments - Category 3 (Uninsured & unregistered and held by banks trust or agent not in OUC's name):
Repurchase agreements.............................................
10,663 12,094 Total Cash, Cash Equivalents and Investments 724,917 692,775 Total Cash, Cash Equivalents and Investments:
Restricted Assets:
Debt service and related funds:
Principal and interest funds.............................................
63,085 62,564 Debt service reserve funds.............................................
114,294 114,039 Total debt service and related funds........................................
177,379 176,603 Construction and related funds:
Nuclear generation facility decommissioning funds.............................
24,144 19,283 Construction funds....................................................
413 42,615 Total construction and related funds........................................
24,557 61,898 Renewal and replacement fund...........................................
47,522 47,883 Customer meter deposits............
15,008 13,420 Total restricted assets...............................
264,466 299,804 Internally Designated Assets:
Self.insurance fund.......................................
4,527 4,589 Liability reduction fund..
328,917 307,422 Stabilization funds...................................................
73.024 43,757 Total internally designated assets..........................................
406,468 355,768 Other Funds:
Cash and investments................................................
55,294 39,096 Less:
Accrued interest receivable from restricted assets.............................
(1,311)
(1,893)
Total Cash, Cash Equivalents and Investments............................
$724,917
$692,775 A-12 ORLANDO UTILITIES COMMISSION
(Dollars in Thousands)
NOTE E -
REGULATORY DEFERRALS Regulatory Assets: Based on regulatory action taken by OUC's governing board, OUC has recorded the following regulatory asset that will be included in the ratemaking process and recovered in future periods:
Deferred Interest Expense: This account represents interest costs on Series 1993 and 1993B bonds which are in excess of interest costs that would have been incurred on short-term debt. OUC elected to defer this additional interest cost for rate-setting purposes until beginning in fiscal year 1996. OUC's total regulatory costs for Deferred Interest Expense are $8,569 and $8,977 in 2001 and 2000, respectively. Deferred interest expense on bonds is currently amortized to interest expense over the life of the Series 1993 and 1993B bonds, amounting to an annual expense of $408 and $408 in 2001 and 2000, respectively.
Regulatory Liabilities: Based on regulatory actions taken by the OUC's governing board, OUC has recorded the following regulatory liabilities that will be included in the ratemaking process and recognized as revenues in future periods:
"* Deferred Gain on Sale of Assets: On October 5, 1999, OUC sold its steam units at the Indian River Plant (IRP) and received a pre-payment from the buyer for twenty (20) years worth of transmission access (recorded as deferred revenue). At the time of sale, OUC elected to defer the gain on sale of approximately $144,000 and begin systematically recognizing a portion of this amount
($45,000) over a four (4) year period to offset generating facility demand payments (Note J) of $11,178 and $9,717 recognized in 2001 and 2000, respectively.
Deferred Wholesale Trading Profits: This account represents a portion of profits generated from wholesale electric sales.
"* Electric and Water Rate Stabilization: OUC's governing board established these accounts for costs (revenues) that are to be recovered by (used to reduce) rates in periods other than when incurred (realized).
"* Fuel Stabilization: This account was established in accordance with guidelines from the Public Utilities Regulatory Policies Act of 1978 and represents the difference between the fuel costs charged to customers and the fuel costs incurred.
Customer Retention Stabilization: This account was established to assist in retaining existing customers and attracting new customers.
"* Health Insurance Reserve: OUC's governing board established this account to mitigate unexpected increases in medical costs to OUC employees.
In conjunction with the recording of these regulatory liabilities OUC's governing board has internally designated certain cash and investments to fund these deferrals (See Note D). Each of these funds earns the same interest rate as OUC's operating investment portfolio.
OUC's total regulatory liabilities are as follows:
September 30 DESCRIPTION 2001 2000 Deferred wholesale trading profits....
$ 43,464
$ 25,805 Rate stabilization......
39,437 33,841 Fuel stabilization.....................................................
15,978 8,394 Customer retention stabilization.............................................
1,610 1,522 Total regulatory liabilities included in deferred revenue...........................
100,489 69,562 Deferred gain on sale of assets..............................................
123,437 135,203 Health insurance reserve 427 427 Total regulatory liabilities...............................................
$ 224,353
$ 205,192 2001 ANNUAL REPORT A-13
(Dollars in Thousands)
NOTE F -
SELF-INSURANCE OUC's self-insurance program covers a portion of its workers' compensation, general liability and automobile liability exposures.
A self-insurance cash and investments account is used to pay claims as incurred. The self-insurance program liability is included in the balance sheets under the caption, Accounts payable and accrued expenses. Changes in the balances of the self-insurance program liability during fiscal years 2001 and 2000 were as follows:
September 30 2001 2000 Balance, beginning of year...............................................
$ 388
$ 479 Claims and changes in estimates..........................................
264 363 Payments of claims....................................................
(299)
(454)
Balance, end of year
$353
$ 388 Under the self-insurance program OUC is liable for all claims up to certain maximum amounts per occurrence on an annual basis.
Claims in excess of the maximum amounts are covered by insurance. Claims have not exceeded these maximum amounts in any of the past several fiscal years. The maximum amounts at September 30 are as follows:
September 30 2001 2000 Workers' compensation.....
$ 250
$ 250 General liability.......................................................
1.000 1.000 Automobile liability....................................................
1,000 1,000 OUC's transmission and distribution system is not covered by insurance, since such coverage is generally not available.
It is the 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 liability for claims orjudgements by one person for general liability to $100 or a total of $200 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 liability of nuclear reactor owners to the amount of the insurance available from private sources and under an industry retrospective plan. Both majority owners (Florida Power & Light and Florida Progress Corporation) maintain the maximum amount of private liability insurance ($200,000) 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. 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.
A-141 ORLANDO UTILITIES COMMISSION
(Dollars in Thousands)
NOTE G -
LONG-TERM DEBT Long-term debt principal outstanding is as follows:
September 30 Issue Date 2001 2000 SENIOR LIEN:
Series 1992 and 1993, 2.4% to 6%
December 1992 449,460 472,275 due serially to 2013 and 5.0% to 5.125%
and due in term form In years 2019 and 2023 September 1993 Series 1996A issued in Term Rate Mode with a mandatory purchase date of 2001 November 1996 60,000" 60,000 at an interest rate of 4,25%
Series 1996B issued as a Fixed Rate Bond due 2011 at a rate of 5.10% or a yield of November 1996 39,995 39,995 5.24%
549,455 572,270 JUNIOR LIEN:
Series 1989D, 1991A and 1992A, 5.00% to December 1989 408,745 443,845 6.75% due in term form in years from through 2017 to 2027 August 1992 Series 1993A and 1994A, 4.10% to 5.50%
June 1993 219,650 220,715 due serially 2000 to 2012 and 5.00% to and 5.50% in term form in years 2012 to 2023 January 1994 Series 1993B, 4.55% to 5.40% due serially August 1993 128,435 131,190 1999 to 2009, 5.25% in term form in year 2023 and Select Auction Variable Rate Securities and Residual Interest Bonds, 5,60% and 5.664% due 2013 and 2017 Series 2001A, 4.00% to 5.25% due serially July 2001 37,040 2002 to 2020 793,870 795,750 OTHER DEBT:
Series 1998A, B and C and 1999A September 1998 160,000 160,000 Revenue Bond Anticipation Notes with annual and and variable rates from 3.5% to 4,48% due September 1999 2003 to 2004 Line of credit -
Note 0 September 1998 25,965 11,701 185,965 171,701 Less current portion (54,190)
(38,336)
Total Long-Term Debt
$ 1,475,100
$ 1,501,385
-See Note P related to subsequent event.
2001 ANNUAL REPORT IA-15
(Dollars in Thousands)
NOTE G -
LONG-TERM DEBT (continued)
Following is a schedule of annual principal and interest sinking fund requirements on the revenue bonds and interest on other notes outstanding at September 30, 2001:
Fiscal Year Ending Principal Interest Total 2002 29,600 76,736
$ 106,336 2003 91,385 75,169 166,554 2004 132,890 71,508 204,398 2005 34,955 66,163 101,118 2006 36,925 64,192 101,117 Thereafter to maturity 1,149,345 665,608 1,814,953 Total
$1,475,100
$1,019,376
$2,494,476 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.
OUC has covenanted in the 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 twenty-five percent (125%) of the annual debt service requirements for the bonds, and that the net revenues shall 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, which is comprised of the Interest, Principal, Investment, Bond 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 deposited In the Revenue Fund and shall be applied only in the following manner:
- 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 lawful purpose in connection with the water and electric system and (B) to make any payments of funds to the City of Orlando -
provided, however, that none of the revenues is ever to be used for the purposes described in (Al and (B) unless all payments required in (1) above, including any deficiencies for prior payments, have been made in full to the date of such use, and OUC shall have fully complied with all covenants and agreements contained in the bond resolution.
Junior Lien Bonds: The junior lien bonds are payable from, and secured by, a lien upon and a pledge of the net revenues derived by OUC from the operation of the water and electric system and certain investment income, subject to the prior lien thereon of OUC's outstanding senior lien bonds. OUC has covenanted in the junior lien bond resolution to fix, establish and maintain such rates and collect such fees, rentals or other charges for the services and facilities provided in each fiscal year, net revenues which will be adequate after the deduction of amounts required to be deposited from net revenues in each fiscal year to provide for the annual debt service requirement for senior lien bonds, to fund any debt service reserve requirement for such senior lien bonds and to make any required deposit to other funds and accounts established under documents evidencing or securing senior lien bonds at all times to pay in each fiscal year the sum of at least (I) one hundred percent (100%) of the annual debt service requirement for the bonds issued pursuant to the resolution and any pan passu additional bonds hereafter issued for the then current fiscal year and (11) one hundred percent (100%) of the amount required to be deposited into the Demand Charge Component Account for the then current fiscal year, and that such net revenues will be sufficient to make all other payments required by the terms of the resolution and 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-161 ORLANDO UTILITIES COMMISSION
(Dollars in Thousands)
NOTE G -
LONG-TERM DEBT (continued)
The junior lien bond resolution establishes the Sinking Fund which 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.
Defeased Bonds: Refunding proceeds were invested in United States obligations in irrevocable Escrow Deposit Trust Funds. Such United States obligations mature at such time so 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.
In July 2001, OUC issued the Water and Electric Subordinated Revenue Refunding Bonds Series 2001A (Series 2001A Bonds) in the amount of $37,040 to advance refund $35,100 of the Series 1992A Bonds (Refunded Bonds). Sale proceeds were invested in United States obligations in an irrevocable Escrow Deposit Trust Fund. Such United States obligations 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 Refunded Bonds. The 1992A Series has a remaining principal balance of $39,420 at September 30, 2001. Present value savings of $2,288 or 6.52% of the Refunded Bonds resulted from the transaction. An economic loss of $2,742 is Included in the accounts which comprise unamortized discount and deferred amount on refunding and will be amortized on a straight-line basis over the life of the Series 2001A Bonds.
All Refunded Bonds are treated as extinguished debt for financial reporting purposes and have been removed from the balance sheet.
Defeased debt principal outstanding is as follows:
Refunded Refunding Final Series Series Payment Remaining Outstanding as Principal @
of Refunding 9/30/01 1973 1978 2003
$ 13,525 2,000 3,000 1975B 1978 2005 9,730 4,525 4,695 1976 1978 2002 8,500 1,000 2,000 1978 (1) 1978 4/1/2008 94,650 1,100 1,715 1978 1985 4/1/2006 110,330 70,070 72,315 1978A 1985 4/1/2008 40,000 21,780 24,260 1978B 1985 4/1/2003 75,000 18,290 26,840 1982 1985 10/1/2003 110,000 37,100 46,285 1991A (2) 1994A 10/1/2020 120,440 120,440 120,440 1992A (3) 2001A 10/1/2020 35,100 35,100 Total
$617,275
$ 311,405
$301,550 (1) Special Obligation Bonds, Series 1978.
(2) The Series 1994A bonds only refunded a portion of the Series 1991A Bonds.
(3) The Series 2001A bonds only refunded a portion of the 1992A Bonds.
2001 ANNUAL REPORT IA-17 Remaining Principal @
9/30/00
(Dollars in Thousands)
NOTE G -
LONG-TERM DEBT (continued)
Related Debt Information: On December 1, 1996, OUC entered into two additional interest rate swap agreements in the notional amounts of $60,000 and $40,000. These agreements provide that OUC receives fixed rates of 4.2843% and 4.976%, respectively, and owes interest calculated at a variable rate based on the BMA (Bond Market Association) Rate. The agreements terminate on October 1, 2001 and October 3, 2011, respectively. The agreement that terminated on October 1, 2001 was not renewed.
Under the swap agreements, only the net difference in interest calculated at fixed and variable rates is actually exchanged with the counter party. The notional amounts are the basis on which interest is calculated; however, the notional amounts are not exchanged.
A termination of the swap may result in OUC's making or receiving a termination payment. However, OUC does not anticipate nonperformance by the counter party.
OUC has no material operating or capital leases.
NOTE H -
ELECTRIC SUPPLY AGREEMENTS Power Sales Contracts: The following table provides a summary of OUC's power sales contracts with other companies.
UNIT SALES SYSTEM SALES TOTAL No. of Amount of No. of Amount of No. of Amount of Year Contracts Sales MW Contracts Sales MW Contracts Sales MW 2002 3
203 2
110 5
313 2003 3
182 2
113 5
295 2004 3
120 2
103 5
223 2005 1
43 1
103 2
146 2006 1
22 1
117 2
139 2007 1
7 1
139 2
146 2008 0
0 1
142 1
142 2009 0
0 1
144 1
144 2010 0
0 1
146 1
146 NOTE I -
PAYMENTS TO THE CITY OF ORLANDO AND ORANGE COUNTY Two types of payments are made to the City of Orlando pursuant to agreements between OUC and the City of Orlando: a revenue-based payment and an income-based dividend payment. The revenue-based payment is calculated at six percent of gross retail electric and water billings to customers within the City. This payment is made pursuant to a policy established by OUO and classified as an operating expense. The income-based dividend payment, is recorded as a reduction of retained earnings rather than as an operating expense. The dividend is calculated using 60% of net Income for all operating units except those operated under the OUC/Trigen Cinergy Solutions agreement (as noted in Note 0) less depreciation related to assets contributed by developers and customers.
Dividends for operating units under this agreement are calculated based on 50% of net income up to $625 and 60% thereafter.
Dividends for fiscal years 2001 and 2000 amounted to $32,091 and $30,784, respectively, including accrued dividends at September 30, 2001 and 2000 of $6,891 and $6,784, respectively.
Payment is also made to Orange County, pursuant to a policy established by OUC. This payment is based on one percent of gross retail electric billings within the County but outside the city limits of the City of Orlando.
A-181 ORLANDO UTILITIES COMMISSION
(Dollars in Thousands)
NOTE J -
COMMITMENTS AND CONTINGENT LIABILITIES
- 1.
OUC and the other participants in SECI and SEC2 have entered into coal supply contracts which expire in 2005 and 2006, with renewal and/or market price reopeners of five years on both contracts. The contracts require minimum annual purchases as follows:
2002 2003 2004 2005 2006
$38,122
$38,741
$39,371
$40,015
$18,812
- 2. OUC and the other participants in SECI and SEC2 have also agreed to a contract that expires on December 31, 2007 for rail delivery of the units' coal purchases.
- 3.
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 SECI and SEC2. The term of contract expires on December 31, 2007.
- 4. OUC has entered Into contracts which expire during fiscal years 2004 and 2014 with ten-year renewal options for natural gas transportation capacity. In addition, OUC has entered into a contract effective fiscal year 2004 with a minimum term of ten years for natural gas transportation capacity for the Stanton Energy Center - Unit A combined cycle plant. The contracts require minimum annual capacity charges. The minimum annual capacity charges are as follows:
2002 2003 2004 2005 2006 2007-201.4
$ 4,551
$ 4,551
$ 20,002
$ 20,594
$ 20,700
$ 20,700
- 5. In connection with the sale of assets described in Note E, OUC has entered into a purchase power agreement with Reliant Energy for generation capacity at the Indian River plant site. This agreement extends through fiscal year 2003 with options to extend the agreement through fiscal year 2007. The contract requires minimum annual capacity charges ranging from $28,000 to $31,000 annually, through fiscal year 2003.
2001 ANNUAL REPORT I A-19
(Dollars in Thousands)
NOTE K -
PENSION PLANS 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 January 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 service is credited. Benefits are vested after 5 years of service.
OUC is the administrator of the plan. OUC established the plan and has the authority to make changes thereto. The plan does not issue stand-alone financial reports, but does receive annual actuarial reports.
Funding Policy: The pension plan agreement requires OUC to contribute, at a minimum, amounts actuarially determined. The current rate of contribution required by OUC is 8.18% of annual covered payroll. Required participant contribution obligations are 4% of earnings until the later of age 62 or completion of 30 years of service, with no required contributions thereafter. The benefit reduction for early retirement is 1% per year. Since the last valuation, the plan began paying a one-time increase in pension to retirees as of October 1, 2000. The increase generally tracks the change In Consumer Price Index from each person's date of retirement. The provision has raised the annual required contribution by $882 or 2.61% of covered payroll.
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 as follows:
September 30 2001 2000 Annual required contribution.....
$2,308
$2,152 Interest on net pension asset................................................
. (127)
(113)
Adjustment to annual required contribution 136 153 Annual pension cost (per actuary).........................................
2,317 2,192 Contributions made......
(2,076)
(2,311)
Increase (decrease) in net pension asset (241) 119 Net pension asset beginning of year......................
1,491 1,372 Net pension asset end of year
$1,250
$1,491 The annual required contributions were determined as part of the October 1, 2000 and 1999 actuarial valuations using the aggregate actuarial cost method. The actuarial assumptions included the following:
Fiscal Year 2001 2000 Investment rate of return......
8.50%
8.25%
Projected salary increases...............................................
5.75%
6.00%
Inflation component....................................................
4.00%
4.00%
The actuarial value of assets was determined using techniques that smooth the effects of short-term volatility in the market value of investments over a five-year period. The over-funded pension asset is being amortized on a level dollar basis over a closed period of 15 years.
A-201 ORLANDO UTILITIES COMMISSION
(Dollars in 7housands)
NOTE K -
PENSION PLANS (continued)
Three-Year Trend Information Annual Percentage Fiscal Year Pension Cost of (APC)
Net Pension Ending (APC)
Contributed Asset September 30, 2001
$2,308 90%
$1,250 September 30, 2000
$2,152 105%
$1,491 September 30, 1999
$2,391 102%
$1,372 Defined Contribution Plan All employees who regularly work 20 or more hours per week and were hired on or after January 1, 1998, are required to participate in a defined contribution retirement plan established under section 401(a) of the Internal Revenue Code and administered by OUC. In addition, employees hired prior to January 1, 1998, were offered the option to convert their Defined Benefit Pension Account to this plan. The plan was created by resolution of OUC.
Under the plan, each eligible employee, upon commencement of employment, is required to contribute 4% of their salary, with OUC making a matching contribution of 4%. In addition, OUC will match up to 2% for additional voluntary contributions. Employees are fully vested after one year of employment. Total contributions for the years ending September 30, 2001 and September 30, 2000 were
$1,300 ($608 employer and $692 employee) and $1,085 ($491 employer and $594 employee), respectively.
NOTE L -
OTHER POST-EMPLOYMENT BENEFITS In addition to the pension benefits described in Note K, OUC has a policy to provide health care benefits and life insurance coverage to all employees who retire on or after attaining age 55 with at least 10 years of service or at any age after completing 25 years of service. Currently 453 retirees meet the eligibility requirements. Retirees may also elect to provide health care insurance for their qualifying dependents by paying 35 percent of the calculated premium. Medical benefits will be available, but not subsidized, for employees who retire under the Defined Contribution Pension Plan. OUC is a secondary provider for those retirees and/or their dependents who are eligible for Medicare benefits.
OUC's health care plan is administered through an insurance company on a self-insurance program with an additional purchased insurance policy to cover those claims over $150. In this plan, the insurance company administers the plan and processes the claims according to benefit specifications, with OUC reimbursing the insurance company for its payouts. Expenses are recorded by OUC when paid to the insurance company. Total post-employment health care costs recognized by OUC for the years ending September 30, 2001 and 2000, were $3,210 and $2,864, respectively. Post-employment life insurance costs during the same periods were $29 and $26.
2001 ANNUAL REPORT IA-21
(Dollars in Thousands)
NOTE M -
REGULATION AND COMPETITIVE ENVIRONMENT According to existing laws of the State of Florida, the five board members of the Orlando Utilities Commission act as the regulatory authority for the establishment of electric and water rates. The Florida Public Service Commission (FPSC) has authority to regulate the electric "rate structures" of municipal utilities in Florida. It is believed that "rate structures" are clearly distinguishable from the total amount of revenues which a particular utility may receive from rates, and that distinction has thus far been carefully made by the FPSC.
Prior to implementation of any rate change, OUC notifies customers individually, holds a public workshop, and files the proposed tariff with the FPSC.
Rorlda Public Service Commission: As noted above, the FPSC has jurisdiction to regulate electric "rate structures" of municipal utilities.
In addition, the Florida Electric Power Plant Siting Act and the Transmission Line Siting Act have given the FPSC exclusive authority to approve the need for new power plants and transmission lines. The FPSC also exercises jurisdiction under the Florida Energy Efficiency and Conservation Act as related to electric use conservation programs and prescribes conformance to the Federal Energy Regulatory Commission's Uniform System of Accounts. The FPSC also approves territorial agreements and settles territorial disputes.
Environmental and Other Regulations: Operations of OUC are subject to environmental regulation by Federal, State and local authorities and to zoning regulations by local authorities. OUC's interconnection agreements with investor-owned utilities are subject to review and approval by the FERC. FERC also exercises jurisdiction over OUC under the Public Utility Regulatory Policies Act of 1978.
In accordance with FERC Order No. 2000 the state of Florida has begun the formation of a Regional Transmission Organization (RTO).
The RTO is an independent organization intended to develop market driven congestion management as well as provide one stop shopping for all transmission and eliminate pancake rates (the layering of rates for each time a trade crosses a corporate boundary).
OUC is actively participating with the other utilities in the state of Florida to detail the establishment of this organization. Currently several options are under consideration on how the transmission assets owned by each utility will be transferred to the RTO.
Competition: The electric utility industry is facing increasing competitive pressure. OUC currently faces competition from other suppliers of electrical energy to wholesale customers and from alternative energy sources for other customer groups. Various states, other than Florida, have either enacted legislation or are pursuing initiatives designed to deregulate the production and sale of electricity. By allowing customers to choose their electricity supplier, deregulation is expected to result in a shift from cost-based rates to market-based rates for energy production. Similar initiatives are also being pursued on the federal level. Although the legislation and initiatives vary substantially, common areas of focus include when market-based pricing will be available for retail customers, what existing prudently incurred costs in excess of the market-based price will be recoverable and whether generation assets should be separated from transmission, distribution and other assets. Further, other aspects of the business, such as generation assets and long-term purchase power commitments, would need to be reviewed to assess their recoverability in a changed regulatory environment.
A-221 ORLANDO UTILITIES COMMISSION
(Dollars in Thousands)
NOTE N -
BUSINESS SEGMENTS The following is a summary of the significant information:
Electric Water Total Year Ending September 30, 2001:
Operating revenues.............................
$ 497,597
$ 38,997
$ 536,594 Depreciation and amortization.............................
66,859 10,389 77,248 Operating income...............................
81,822 8,208 90,030 Net income (loss)...............................
56,675 (3,190) 53,485 Dividends to the City of Orlando...........................
34,005 (1,914) 32,091 Construction work in progress additions...............
92,968 18,577 111,545 Net working capital..............................
96,698 19,666 116,364 Total assets...................................
2,051,502 359,825 2,411,327 Long-term debt -
net............................
1,185,055 182,894 1,367,949 Total equity.......
462,355 157,428 619,783 Electric Water Total Year Ending September 30, 2000:
Operating revenues.............................
454,236
$ 46,895
$ 501,131 Depreciation and amortization.............................
56,967 11,591 68,558 Operating income...............................
77,093 16,059 93,152 Net income...........................................
47,452 3.855 51,307 Dividends to the City of Orlando............................
28,471 2,313 30,784 Construction work in progress additions...............
44,210 23,793 68,003 Net working capital..............................
110,628 12,353 122,981 Total assets.......................................
2,007,966 358,245 2,366,211 Long-term debt -
net............................
1,173,020 215,323 1,388,343 Total equity.........
475,463 122,968 598,431 2001 ANNUAL REPORT A-23
(Dollars in Thousands)
NOTE 0 -
MAJOR CONTRACTS AND AGREEMENTS Interlocal Agreement between OUC and the City of St. Cloud: On April 25, 1997, OUC entered into an interlocal agreement with the City of St. Cloud (STC) to assume responsibility for providing retail electric energy services to all STC customers and to assume control and operation of STC's electric transmission and distribution system and certain generation facilities. In return, OUC is obligated to pay STC 9.5% of retail sales provided to STC customers (a minimum of $2,361 annually, unless certain events occur) and to pay STC approximately $2,232 annually, less certain contingent credits, for use of its electric system. The term of the Agreement commenced May 1, 1997 and continues in effect until September 30, 2022. OUC's revenue includes $30,335 and
$28,247 for fiscal years 2001 and 2000, respectively, as a result of this agreement.
Agreement between OUC and Trlgen Cinergy Solutions: OUC entered into an agreement dated June 23, 1998, with Trigen Cinergy Solutions (TCS), to provide air conditioning cooling systems for buildings in the Orlando metropolitan area. The agreement with TCS also provides for interim funding up to $35,000 and defines OUC as the sole owner of the Chilled Water facilities once construction is complete. OUC has borrowed $25,965 and $11,701 as of September 30, 2001 and 2000, respectively, in funding from TCS for these projects. As of December 31, 2001 this agreement will expire and it Is OUC's intention to obtain alternative funding.
OUC shares profits and losses with TCS in accordance with the agreement. OUC also includes profits from the Chilled Water project in its calculation of a transfer of payments to the City of Orlando as described in a separate agreement dated August 17, 1998 (see Note I).
NOTE P -
SUBSEQUENT EVENTS In the month of October, 2001 OUC had two bond transactions. The first transaction related to the remarketing, in a secondary market transaction, of the Water and Electric Revenue Bonds, Series 1996A (Multi-Modal) in the amount of $60,000. The 1996A Bonds were remarketed in the Term Rate Mode with a mandatory purchase date of October 1, 2008. No gain or loss was recognized on this transaction and the 1996A Bonds will bear interest beginning October 1, 2001 at an interest rate of 4.10%.
The second transaction, executed on October 30, 2001, related to the refunding of all or a portion of certain Series of Water and Electric Revenue Bonds and Water and Electric Subordinate Revenue Bonds, in the amount of $258,815, Present value savings of
$19,157 or 6.92% of the Refunded bonds resulted from the transaction. An economic loss of $39,481 will be included in the unamortized discount and deferred amount on refunding on the September 30, 2002 balance sheet.
The OUC Water and Electric Revenue Refunding Bonds Series 2001 were issued under OUC's new General Bond Resolution adopted by OUC on October 9, 2001. The terms of this new general bond resolution do not become effective until in excess of 51% of OUC's outstanding Junior and Senior debt obligations have been issued under this resolution. As such it is not anticipated these covenants will become effective within the upcoming year.
A-241 ORLANDO UTILITIES COMMISSION
Deloitte & Touche LLP Certified Public Accountants Suite 1800 200 South Orange Avenue Orlando, Florida 32801 Tel: (407) 246 8200 Deloitte Fax: (407) 422 0936 S&
Touche Www.us deloit texcont INDEPENDENT AUDITORS' REPORT To the Commissioners of the Orlando Utilities Commission:
We have audited the accompanying balance sheets of the Orlando Utilities Commission ("OUC") as of September 30, 2001 and 2000, and the related statements of revenues, expenses and changes in retained earnings and of cash flows for the years then ended. These financial statements are the responsibility of OUC'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 OUC as of September 30, 2001 and 2000, 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.
In accordance with Government Auditing Standards, we have also issued our report dated November 21, 2001 on our consideration of OUC'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 Auditing Standards and should be read in conjunction with this report in considering the results of our audit.
November 21, 2001 Detoitte Touche Tohmat.su 2001 ANNUAL REPORT IA-25
ouc*
TIK( JRlalialc' Onc 500 South Orange Avenue Orlando, Florida 32801 Phone: 407.423.9100 Fax: 407.236.9616 www.ouc.com 1ý
SEMINOLE ELECTRIC COOPERATIVE, INC.
2001 ANNUAL REPORT The Cooperative Way of Doing Business...
What Could be More American?
Contents Dialogue and collaboration enable Seminole's leadership success.
From left, Steve Shearer, Neil Phinney, Steve Wallace, Trudy Novak, Ken Bachor, Garl Zimmerman and Lane Mahaffey participate in a tactical team planning session.
Mission, Vision, Values 2 From the President and General Manager 4 Year in Review 7 Working Together 9 Building for the Future 11 Our Commitment to the Community 15 Looking Ahead 17 Board of Trustees 18 Member System Statistics 20 Corporate Information 22
MIS SIO1 To be the preferred provider of wholesale energy services for our members.
Our Vision To be a leading competitor in the emerging energy market, trusted and respected by our customers, employees, and community. Through devotion to customer satisfaction and continually striving to exceed expectations, we will provide the best value in wholesale energy service. We will provide employees a challenging and rewarding work environment, where pride and commitment are the hallmark of our operations.
q, VISION
& VALUES Our Values We uphold the highest ethical and professional standards.
We believe that cooperative ownership and principles are the cornerstone of our success.
We affirm that quality, innovation, communication and teamwork are essential ingredients to achieve customer satisfaction.
We improve the quality of life in our communities.
We believe in prudent and cost-effective policies to protect our environment.
ri
1 V'
q A,frht&
About Seminole Seminole Electric is a generation and transmission cooperative. We provide bulk supplies of electricity to 10 member distribution cooperatives that serve electric consumers in 45 Florida counties, from the Georgia border to the Everglades.
More than 1.5 million individuals and businesses rely on Seminole and its members for their electric power.
Seminole's primary generating facility, the Seminole Generating Station, consists of two 650 megawatt coal-fired generating units. It is located north of Palatka on the St. Johns River, in Putnam County, about 50 miles south of Jacksonville. A second generating facility went into commercial service on January 1, 2002. Seminole's Payne Creek Generating Station is a 500 megawatt, gas-fired, combined cycle facility. It is located in Hardee County, about 12 miles northwest of Wauchula.
The Cooperative also owns a 14 megawatt share of Florida Power Corporation's Crystal River 3 nuclear plant, 68 miles of double circuit 230 kilovolt (kV) transmission line, 134 miles of single circuit 230 kV line, and 141 miles of 69 kV line.
Seminole has purchased power and interchange agreements with other utilities, and various purchase and sale agreements with independent power producers and power marketers. These agreements allow us to provide our members a diverse and cost-effective mix of power supply resources to supplement our generating facilities.
The Seminole Board of Trustees sets policies that govern the Cooperative's day-to-day operations. It is comprised of two trustees and one alternate from each of our member cooperatives.
SEMINOLE ELECTRIC COOPERATIVE 2001 OPERATING
SUMMARY
Total Revenues
$669,077,708 Net Margins
$2.415440 Total Assets
$1 014.411,269 Energy Sales 12,911 GVVH to Member Cooperatives Seminole System 3,491 MW Coincident Peak Demnand 3
SEMINOLE ELECTRIC COOPERATIVE, INC.
ANNUAL REPORT 2001
WILSON G. SHEPPARD RICHARD J. SIIDULLA WE BELIEVE there's nothing more American than people banding together, by choice, to help each other and themselves. That's one simple definition of a cooperative. But co-ops weren't born in America.
They're immigrants - another uniquely American characteristic.
According to some sources, the first formal business co-op was formed in 1821 in Great Britain. Much more is known about another, successful English co-op, the members of The Rochdale Society of Equitable Pioneers.
The Pioneers were formed in 1844. Its members are described by one historian as having had a rare mixture of realism and vision; "their feet on the ground and their head in the clouds." They believed in the possibility of a better way and had faith in both the idea and the ideals of cooperation.
Historian G.J. Holyoake described what Rochdale's meinber-owners were able to achieve - a successful cooperative business - as a "moral miracle." Rochdale's members, he wrote, had the good sense to "differ without disagreeing; to dissent... without separating; to hate at times, and yet always hold together." The Pioneers created a set of principles to guide their efforts and then worked to advance their principles, wrote Holyoake, "with singleness of purpose."
The Seven Rochdale Principles Voluntary and open membership Democratic member control Members' economic participation Autonomy and independence Education, training, and information Cooperation among cooperatives Concern for community A COMMITMENT TO MUTUAL GOOD IS ONE WE ALL CAN MAKE TODAY. None of us is immune from the pain of the attacks that occurred on September 11, 2001, and their aftermath. These tragedies prompted many people to reconsider their priorities, their commitments, and the destructive results of hatred and intolerance. Today more than ever, the principles of cooperation provide a positive framework for building a more successful, collaborative world.
41 SEMINOLE ELECTRIC COOPERATIVE, IN ANNUAL REFPORT 2001 f
II I
FROM THE PRESIDENT AND GENERAL MANAGER SEMINOLE'S PLANS AND ACTIONS are shaped by our commitment to cooperative ownership, to our members, and to our communities. We believe in the cooperative form of business. While today's energy market appears headed toward increasing competition, the real and continuing success of the cooperative model offers a viable alternative. A more collaborative approach to energy supply and distribution may in fact, better benefit America, which relies on an affordable supply of energy to grow its economy.
Many of the activities and achievements that mark 2001 as a year of growth for Seminole are discussed on the following pages. To illustrate this year's report we are proud to feature photos that reflect the patriotism of our members and their consumer-owners. Displaying the American flag honors those who defend America's values and principles, and honors the freedoms we value.
We appreciate your interest in this report and Seminole Electric Cooperative, Inc. We are proud to be an American cooperative, governed by our members, for our members. More than 1.5 million business and residential consumers rely on Seminole for their wholesale energy needs. We will continue to do our best to make their investment in Seminole work as hard as they do, for their benefit.
Richard J. Midulla Executive Vice President and General Manager Cooperative (n)
The Oxford English Dictionary (OED) is considered one of the most complete resources on the history and use of words in the English language.
We looked there to do a little digging about cooperatives.
The OED defines the noun, cooperative, as, "short for co-operative store or co-operative society," or, "an association providing services of various kinds to its members." Cooperative society is further defined as "a society or union of persons (formed) for the production or distribution of goods, in which the profits are shared by all the contributing members."
Wilson G. Sheppard President, Board of Trustees 5
SEMINOLE ELECTRIC COOPERATIVE, INC.
ANNUAL REPORT 2001
THE YEAR IN REVIEW January 2001 Seminole members set new record peak demand of 3517 megawatts on January 5. The previous record was 3147 megawatts, set on January 6, 1999.
February 2001 The Florida Public Service Commission unanimously approves a joint application filed by Seminole and Calpine Corporation for Calpine's Osprey Energy Center. Seminole will purchase the majority of the power from this 530 megawatt, combined cycle generating facility for a period of at least five years, beginning in June 2004.
March 2001 Mike Opalinski, director of environmental affairs, speaks to industry executives, government officials and educators at a power production workshop sponsored by the Council for a Sustainable Florida, on the topic of "social responsibility and community partnerships." The focus:
Seminole's synthetic gypsum project and the Cooperative's alliance with Lafarge Corp.,
a wallboard manufacturer.
Seminole's Board increases member levelized fuel rate from 23.53 mills/kWh to 27.58 mills/kWh, due to continued high level of natural gas prices.
April 2001 Seminole receives a leadership award from the Council for Sustainable Florida. Seminole's application features the Seminole Generating Station gypsum conversion program as an example of its sustainable business practices. The award recognizes Seminole's emphasis on environmental stewardship and community service.
May 2001 Rural Electrification's cover highlights the effective supply management practices at various electric cooperatives, including Seminole.
Seminole retires approximately
$562,000 in capital credits to its 10 members. Since1987, the Cooperative has refunded more than $15.5 million in capital credits to its members.
June 2001 Florida's power plant siting board (Governor Jeb Bush and his Cabinet) approves the Seminole/
Calpine application for Osprey Energy Center (see February).
July 2001 Synthetic gypsum production continues at Seminole Generating Station. A conveyor system is now in service, automating transfer of the product to Lafarge Corp.
August 2001 "First fire" of Payne Creek Generating Station's combustion turbine #1, marking the start of the unit's transition from construction to start-up mode.
September 2001 Seminole's Board approves a decrease in the levelized fuel rate from 27.58 mills/kWh to 24.12 mills/kWh, effective October 1, thanks to a decrease in natural gas prices. The 27.58 rate had been in effect for only six months.
October 2001 November 2001 Contract f
f Re-Energizes A&9.1 Polk Plant Tim Woodbury, Vice President of Strategic Services, speaks at the groundbreaking ceremony for Calpine Corp.'s Osprey Energy Center in Auburndale.
Seminole will purchase power from this facility beginning in June 2004.
December 2001 Seminole begins purchasing power from two combustion turbines (300+ megawatts) from Reliant Energy, a Houston-based energy services company. The generating units are located in Osceola County.
Seminole signs a one year, full requirements natural gas contract with Infinite Energy, Inc. to supply natural gas to the Payne Creek Generating Station, starting January 1, 2002.
< South Seas Plantation Resort (Captiva Island, FL),
a member-consumer of Lee County Electric Cooperative.
Starting October 30, Seminole hosts regional update meetings in three locations around the state to provide information to member system employees and board members. The meetings cover wholesale power issues and Seminole operations, and are very well received.
Seminole receives a $2.2 million refund from the Florida Power and Light Company, related to FPL rates for transmission service in 1996 and 1997.
7 SEMINOLE ELECTRIC COOPERATIVE, INC.
ANNUAL REPORT 2001
a&
'I
"Competition has been shown to be useful up to a certain point and no further, but cooperation, which is the thing we must strive for today, begins where competition leaves off."
FRANKLIN D.
ROOSEVELT The Veterans Iwo Jima statue is located at the base of the Midpoint Memorial Bridge connecting Cape Coral and Ft. Myers, FL. (Photo courtesy of Lee County Electric Cooperative.)
Seminole and Its Members:
Working Together for a Better Cooperative TO BETTER SERVE OUR 10 MEMBER SYSTEMS, Seminole's Board of Trustees has adopted a revised Mission, Vision and Values statement (see page 2), initiated accountability standards, and updated Seminole's strategic goals. One key goal is to identify, develop and implement a process for Key Performance Indicators (KPIs) - a critical measure of our performance and our success. Six KPIs have been identified for tracking and reporting to the Board.
Key Performance Indicators Competitive Wholesale Rate One of the most important measures of our performance is the price of wholesale electric service to our members.
In 2001, we identified measures of competitive performance to be benchmarked. When measured against our competition in the Florida marketplace, our wholesale rate is competitive.
Power Supply Resource Performance The performance of our power supply resources - both owned resources and purchased power - is critical to achieving a competitive wholesale rate. We benchmark our plant availability, forced outage rate, and heat rate, against a regional data base of similar plants. Purchased power resources are evaluated using similar criteria.
Transmission Reliability Transmission reliability is a key issue that supports our service to our members. While it's important to have enough generation to supply member needs, it's equally important for that generation to be delivered reliably to each member.
A major change is taking place in Florida on the transmission side of our business. Due largely to Federal Energy Regulatory Commission (FERC) rulings, transmission facility owners and other electricity suppliers are involved in the formation of a regional transmission organization (RTO). Seminole is working closely with FERC and other Florida utilities to ensure that, whatever form this RTO takes, it will result in comparable treatment for Seminole and its members, regarding transmission access, reliability and pricing.
Financial Performance Seminole's financial performance is tracked using a family of statistical parameters. We compare our results to a trend analysis annually compiled by the National Rural Utilities Cooperative Finance Corporation (CFC), to ensure we're maintaining a strong financial foundation.
Corporate Productivity Corporate productivity indicates how well Seminole uses its resources to accomplish its mission. We have developed performance ratios to indicate trends in Seminole productivity. These are benchmarked against the same peer group used for financial comparisons.
Customer Satisfaction Satisfaction is viewed as members' contentment with Seminole as their preferred power supplier.
We're in the process of developing a survey instrument to measure member satisfaction. Questions will come from the following areas: Relationship Between Seminole and its Members, Rates, Community Reputation, Billing (accuracy, timeliness), Fiscal Responsibility, and Reliability.
< Charlie Wubbena monitors Seminole's transmission system information in the energy management control center, which is located at the headquarters building in Tampa.
Backg'round, an electronic display of Seminole's 230 kV transmission system.
S9 SEMINOLE ELECTRIC COOPERATIVE, INC.
ANNUAL REPORT 2001
"77 K..
LN
"In any moment of decision, the best thing you can do is the right thing.
The worst thing you can do is nothing."
THEODORE ROOSEVELT A Peace member Building for the Future Payne Creek Generating Station - Ready for Commercial Operation DURING 2001, CONSTRUCTION CONTINUED ON SEMINOLE'S Payne Creek Generating Station, a 500 megawatt, natural gas-fired combined cycle generating unit, in preparation for its January 1, 2002 commercial operation date. Twenty-five new staffers were hired and trained to work in multi-craft teams.
Payne Creek is located on a 1300 acre site in Hardee County in south central Florida. It consists of two combustion turbine/generators, two heat recovery steam generators, and a steam turbine/generator. Its output replaces power previously purchased from another Florida utility.
The "first fire" of Payne Creek's combustion turbines took place in August, 2001. First fire is when a unit consumes fuel for the first time, marking the start of the transition from construction to startup mode.
River Electric Cooperative proudly flies the American flag.
Another milestone took place in December, when Seminole signed a one year, full requirements natural gas contract with Infinite Energy, Inc., for Payne Creek.
Infinite Energy manages purchasing, transportation, balancing and billing functions in fulfillment of this agreement.
Commercial operation of Payne Creek enhances Seminole's balanced portfolio of cooperative-owned and purchased power, in addition to adding fuel diversity, to serve our members and their consumers.
A series of "steam blows" took place in September, another step toward putting the station into service.
Buildup can accumulate in the piping during station construction, and must be removed for system operation.
Steam blows remove grit, rust and other debris from the inside of steam piping by forcing pressurized steam through the piping and out a temporary exhaust pipeline.
'he Irst e of I
- est, LitrI ns -L~okplace iii August, 2001.
< The Seminole Payne Creek Generating Station stacks are painted in the colors of Seminole's corporate logo.
S11 SEMINOLE ELECTRIC COOPERATIVE, INC.
ANNUAL REPORT 2001
"I hope I shall possess firmness and virtue enough to maintain what I consider the most enviable of all titles, the character of an honest man."
GEORGE WASHINGTON Another home flag in the servi Sumter Electri Building for the Future continued Looking Out for Our Members - New Relationships with Other Utilities IN ADDITION TO OWNED GENERATION, Seminole plans to meet a portion of its member demand, now and in the future, through purchased power agreements with other utilities and power marketers.
On December 1, Seminole began receiving more than 300 megawatts of firm peaking capacity from Reliant Energy, a Houston-based energy services company. The generating units are located in Osceola County (FL).
Maryland-based Constellation Energy Group broke ground in 2001 on a gas-fired generating facility in Brevard County. Its Oleander Power Plant is scheduled to be in commercial operation by May, 2002. Constellation has committed to begin delivering the energy from two combustion turbines (approximately 175 megawatts each) from this facility to Seminole, beginning December 1, 2002. Output from a third combustion turbine will be made available beginning May 1, 2003. This agreement continues through 2009.
< The Seminole Generating Station in Putnam County, FL.
proudly flies the ce territory of c Cooperative.
In November, Calpine Corporation had a ground breaking/flag raising ceremony for its 530 megawatt Osprey Energy Center in Aubumdale (FL). Florida's Power Plant Siting Board approved a joint Seminole/
Calpine application in June for this facility. Seminole will purchase the majority of the power from the Osprey facility beginning in June, 2004, for a period of at least five years.
We think it's good policy, and good business practice, to encourage partnerships between independent power producers such as Reliant, Constellation and Calpine, and incumbent utilities. Relationships such as these add to our diverse energy portfolio, helping to ensure reliable service to our members at competitive rates.
We also are working to help shape the future nimr1ktpk'ce for wholesale energy here n 1-.05rid oi 13 SEMINOLE ELECTRIC COOPERATIVE, INC.
ANNUAL REPORT 2001
"I'm a great believer in luck, and I find the harder I work, the more I have of it."
THOMAS JEFFERSON The flag flies at Seminole's Payne Creek Generating Station.
Our Commitment to the Community SEMINOLE'S MISSION VISION VALUES STATEMENT includes a commitment to "improve the qiality of life in our communities." Community Service is an important aspect of that comnmitment. We define communi t. service as both environ mental stewardship and the support of community programs and interests.
The Council for Sustainable Florida named Seminole a "leadership" award winner in 2001. Seminole's application featured the Seminole Generating Station's gypsum conversion program as an example of our sustainable business practices. It also discusses how our business practices, programs and policies reflect an emphasis on environmental care taking, and support the interests of our employees and our local communities.
Seminole sells wallboard-grade synthetic gypsum to Virginia-based Lafarge Corporation. Lafarge uses that gypsum to make commercial grade wallboard at its newest manufacturing facility, adjacent to the Seminole Generating Station. Synthetic gypsum is produced from the byproduct of the Station's flue gas desulfurization system. The Lafarge plant created 100 new jobs and increased the tax base for Putnam County.
Revenue from gypsum sales and savings from not having to treat and landfill the byproduct make this project a major coup for Seminole, its members, and the community. Net savings from the sale of gypsum, increased fly ash sales and reduced landfill costs total more than $6 million annually.
As a corporate citizen, Seminole supports United Way campaigns at its three locations (Hardee, Hillsborough, and Putnam counties). In 2001 we raised more than $50,000 for United Way funded programs.
In Hillsborough County, the Cooperative is a corporate sponsor of Hands on Tampa (HOT), a service organization that promotes and facilitates volunteer service. In 2001, Seminole's HOT corporate team members worked more than 200 hours0.00231 days <br />0.0556 hours <br />3.306878e-4 weeks <br />7.61e-5 months <br /> to help meet community needs. Additional employee-led teams supported such programs as the All-American Soap Box Derby (Seminole-sponsored car), the American Cancer Society's Relay for Life, and a holiday party for residents of Rodeheaver Boy's Ranch in Putnam County.
In Putnam and Hardee Counties, Seminole sponsors Newspapers in Education, putting local newspapers in middle and high school classrooms. Also in Putnam County, we're the largest sponsor of the Water Works Museum and Environmental Education Center, which will begin its programs for fourth grade students in spring, 2002.
Seminole is proud to be the leading corporate sponsor of the Palatka Water Works Museum and Environmental Education Center, which will offer its first programs for teachers and students in spring, 2002.
< The 2,311 foot conveyor belt that delivers synthetic gypsum, produced at the Seminole Generating Station, to the adjacent Lafarge Gypsum wallboard plant.
15 SEMINOLE ELECTRIC COOPERATIVE, INC.
ANNUAL REPORT 2001
.1
"There are many ways of going forward, but only one way of standing still."
FRANKLIN D. ROOSEVELT Another flag proudly displayed at a home in the Central Florida Electric Cooperative, Inc. service territory.
Looking Ahead IN CONJUNCTION WITH THE FLORIDA Electric Cooperatives Association and the National Rural Electric Cooperative Association, we're working to stay on top of state and federal legislation that could impact our members.
Federal legislation related to electric utility restructuring was delayed in 2001, primarily due to the meltdown of the California energy market, brought on by, among other things, a poorly designed market structure reflected in the state's deregulation plan. The December bankruptcy filing of Enron Corporation, a major voice in the restructuring movement, also contributed to legislators proceeding with caution regarding a national restructuring bill.
Governor Bush appointed the Florida Energy 2020 Commission in 2000 to examine Florida's energy needs. The Commission submitted its final report in December, 2001. It remains to be seen if any of their recommendations will be acted upon. We believe it's doubtful restructuring will be addressed in the Florida legislature in 2002, for many of the same reasons federal initiatives are being re-examined.
Right now, it appears that further deregulation of Florida's wholesale energy market has lost momentum. Governor Jeb Bush, who continues to back change in the electric utility industry, is reluctant to move too quickly, saying that "...a measured and well-thought-out approach is key to our success." We agree with the Governor, and think it's important that Florida learn from others' mistakes before crafting its own restructuring legislation.
Thee s incre 11 t ""
business-consumer n
- lo, sfnI l
,uppliers who stress value.
§ln stand out and prosper iH a morro DAVID REICHMAN, PRESIDENT RKS Research and Consulting, N. Salem, NY, discussing RKS's November 2001 national survey of business consumers on electric deregulation.
< The Florida Capitol Building, Tallahassee.
17 SEMINOLE ELECTRIC COOPERATIVE, INC.
ANNUAL REPORT 2001
WILSON G. SHEPPARD PRESIDENT The Seminole Board of Trustees THE SEMINOLE ELECTRIC COOPERATIVE BOARD OF TRUSTEES consists of two voting members and one alternate trustee from each member system.
The manager of each member cooperative serves as a voting member.
In January, Amos Sumner, Talquin Electric Cooperative, was named an alternate trustee, replacing Colin English, Jr.
Wilson G. Sheppard, from Sumter Electric Cooperative, was elected to his second term as board president in April, 2001. Sheppard is a J OHN W. DR A K E retired certified public accountant and also serves as president of the VICE PRESIDENT Sumter board of trustees.
In July, Gary Stallons was elected manager trustee from Talquin Electric, replacing William E. Laughlin, who retired.
The Seminole board sets policy and carries out its responsibilities through five committees: Executive, Administrative, Engineering and Operations, Finance, and Rate.
The Administrative, Engineering and Operations, and Finance committees are made up of one trustee from each member system.
The Rate committee consists of the member system managers.
WILLIAM T. MULCAY, JR.
In 2001, Jerry L. Martin, Suwannee Valley Electric Cooperative, SECRETARY/TREASURER served as chairman of this committee.
The Executive committee consists of the board officers and the immediate past president. The board president serves as chairman of this committee.
Th eSeminole 5Ubc:
3f[L3 a
carries out its responsi ilites WILLIAM C. PHILLIPS ASSISTANT SECRETARY/TREASURER 18 SEMINOLE ELECTRIC COOPERATIVE, INC.
ANNUAL REPORT 2001
COMMITTEE MEMBERS ADMINISTRATIVE COMMITTEE Ui L.T. Todd, Glades EC, Chairman Billy E. Brown, Withlacoochee River EC, Vice Chairman Neal Brown, Tri-County EC James R Duncan, Sumter EC Floyd I. Gnann, Clay EC David E. Gomer, Lee County EC Mal Green, Talquin EC W.F. Hart, Suwannee Valley EC Maurice Henderson, Peace River EC Edward I. Ricketson, Central Florida EC ENGINEERING AND OPERATIONS COMMITTEE FINANCE COMMITTEE William C. Phillips, Clay EC, Chairman James E. Hines, Withlacoochee River EC, Vice Chairman James Aul, Glades EC Evans Brown, Tri-County EC Glen 0. Douglas, Peace River EC Pamela M. May, Lee County EC Earl Muffett, Sumter EC Gary Stallons, Talquin EC Clyde Townsend, Central Florida EC J.C. Walker, Suwannee Valley EC William T. Mulcay, Jr., Peace River EC, Chairman Jerry L. Martin, Suwannee Valley EC, Vice Chairman Ronald Bass, Tri-County EC General James Dozier (Ret.), Lee County EC John W. Drake, Glades EC Bennie M. Rivenbark, Withlacoochee River EC Wilson G. Sheppard, Sumter EC C.M. Smith, Jr., Clay EC George A. Stephens, Central Florida EC Amos Sumner, Talquin EC 19 SEMINOLE ELECTRIC COOPERATIVE, INC.
ANNUAL REPORT 2001 I
TOTAL CONSUMERS (year end) 1997 1998 1999 2000 2001 TOTAL ENERGY REQUIREMENTS:
(millions of KWHs) 1997 1998 1999 2000 2001 TOTAL MEMBER SYSTEM (millions of dollars)
ASSETS 19971 19981 19991 2000 2001 20
\\\\\\
l N
N.
PT A. N N tU A. L. 1, E P 0 1, T N
P,
AGGREGATE COINCIDENT PEAK DEMAND*
(megawatts MW) b
ec PERCENTAGE OF TOTAL RETAIL SALES BY CLASS 70% residential 9MIMI 1% other---'Ia 29% commerciallindustrial-TEN MEMBER DISTRIBUTION COOPERATIVES TrUCounay E.O Madison Talquin E C Valley S C CuiO Live Oak
'INCLUDES POWER RECEIVED FROM THE SOUTHEASTERN POWER ADMINISTRATION 21 SEMINOLE ELECTRIC COOPERATIVE.
INC ANNUAL REPORT 20TI Cc? I
1i" ParAin iship with Tlhose We Serve.
RICHARD J. MIDULLA STEVEN R. SHEARER JAMES R. DUREN SEMINOLE ELECTRIC ANNUAL MEETING Seminole Electric trustees are elected to a one-year term at the Cooperative's annual meeting. Board officers are elected at a regular board meeting held later that day.
HEADQUARTERS OFFICE Seminole Electric Cooperative, Inc.
16313 North Dale Mabry Highway P.O. Box 272000 Tampa, Florida 33688-2000 GENERAL COUNSEL ROBERT A. MORA Allen, Dell, Frank and Trinkle P.O. Box 2111 Tampa, Florida 33601 2001 BOARD OFFICERS WILSON G. SHEPPARD, President JOHN W. DRAKE, Vice President WILLIAM T. MULCAY, JR., Secretary/Treasurer WILLIAM C. PHILLIPS, Assistant Secretary/Treasurer EXECUTIVE OFFICER RICHARD J. MIDULLA Executive Vice President and General Manager EXECUTIVE STAFF STEVEN R. SHEARER Senior Vice President and Assistant General Manager, and Assistant Secretary JAMES R. DUREN Vice President, Energy Production JOHN W. GEERAERTS Vice President, Financial Services, and Assistant Treasurer FLOYD J. WELBORN Vice President, Energy Delivery TIMOTHY S. WOODBURY Vice President, Strategic Services JEANETTE L. FLETCHER Executive Assistant to the General Manager 22 SEMINOLE ELECTRIC COOPERATIVE.
INC.
ANNUAL REPORT 2001
CORPORATE INFORMATION JOHN W. GEERAERTS FLOYD J. WELBORN TIMOTHY S. WOODBURY JEANETTE L. FLETCHER STAFF DIRECTORS WILLIAM C. CROSS Director, Information Systems LANE T. MAHAFFEY Director, Corporate Planning TRUDY S. NOVAK Director, Pricing and Bulk Power Contracts MICHAEL P. OPALINSKI Director, Environmental and Engineering Services JAMES G. PITTMAN Director, Plant Operations (Payne Creek Generating Station)
W. JACK REID Director, Fuel Supply RICHARD D. RICH Director, Supply Management W. PAUL SHIPSKIE Director, Plant Operations (Seminole Generating Station)
THOMAS H. TURKE Director, Internal Audit STEVEN R. WALLACE Director, Operations Annual Report Inquiries regarding the contents of this annual report should be directed to Seminole's Human Resources and Public Relations department, or by e-mail to info@seminole-electric.com.
Selected portions of this report may be viewed on our web site at www.seminole-electric.com.
23 SEMINOLE ELECTRIC COOPERATIVE, INC.
ANNUAL REPORT 2001
jSeminok Electric
~PCOO PERATIVE, INC.
IN PARTNERSHIP WITH THOSE WE SERVE 16313 N. Dale Mabry Hwy.
P.O. Box 272000 Tampa, Florida 33688-2000 (813) 963-0994 www.seminole -electric.com
fjSeminole Electric COPERATIVE, INC.
2001 FINANCIAL STATEMENTS IY:./
, :zi}-
- 2 I7' E
- li
SEMINOLE ELECTRIC COOPERATIVE, INC.
(dollars in thousands) 2001 Operating revenues:
Sales to members.......................... $
650,328 Sales to non-members..................
12,128 O ther 6,622 Total operating revenues................
669,078 Operating expenses:
Fuel and other production expenses 234,200 Purchased power and transmission 330,611 Depreciation and amortization....
26,034 Lease of coal-fired plant...............
28,056 Other operating expenses.............
21,184 Total operating expenses................
640,085 Operating margins..........................
28,993 Net interest expense.....................
32,653 Nonoperating income, net...........
6,077 N et m argins.....................................
2,417 Assets:
Utility plant, net...........................
682,856 Investm ents...................................
71,314 Current assets................................
145,454 Deferred charges...........................
114,787
$ 1,014,411 Equity and liabilities:
Equity 72,395 Long-term liabilities.....................
785,393 Current liabilities..........................
130,122 Deferred gain/other deferred credits 26,501
$ 1,014,411 Utility plant additions.................... $
66,318 Working capital..............................
15,332 Megawatt hours sold - members........ 12,946,637 Megawatt hours sold - non-members..... 358,307 Wholesale member cost - mills/kWh......... 50.23 Total sales - mills/kWh..........................
49.79 2000 566,858 13,490 2,308 582,656 213,468 273,428 25,043 28,515 17,249 557,703 24,953 35,343 12,637 2,247 643,003 62,248 195,017 116,251
$ 1,016,519 71,532 777,183 140,799 27,005
$ 1,016,519 1999 549,217 7,026 1,497 557,740 215,590 238,898 25,046 28,747 22,415 530,696 27,044 35,720 11,198 2,522 520,602 61,327 219,451 112,315 913,695 69,915 712,547 105,376 25,857 913,695 147,819 36,223 54,218 114,075 12,727,333 380,547 44.54 44.27 11,849,011 214,752 46.35 46.11 1998 543,251 5,380 11,307 559,938 220,479 230,335 24,964 29,250 25,182 530,210 29,728 38,745 11,512 2,495 526,466 99,361 154,409 56,896 837,132 68,016 658,592 78,929 31,595 837,132 1997 525,118 11,072 1,746 537,936 219,861 205,846 27,143 29,090 21,100 503,040 34,896 39,647 7,457 2,706 539,492 99,774 152,909 62,946 855,121 66,198 678,969 77,534 32,420 855,121 14,252 5,936 75,480 75,375 11,619,034 166,936 46.76 46.55 10,686,941 469,044 49.14 48.06 SEMINOLE ELECTRIC COOPERATIVE, INC.
FINANCIAL STATEMENTS 2001 1
P.1 0 Cl~y OOPERA.TIVE, RESULTS OF OPERATIONS Revenues from sales to members increased approximately 14.7% in 2001 compared to 2000. Fuel revenues increased 8.7% in 2001, reflecting a 1.5% increase in MWhs sold and a 7.1% increase in the rate per MWh charged to members. Non-fuel revenues were 21.6%
higher than in 2000. The increase is primarily due to 2000 non-fuel revenues including the effects of a one time rate rebate of $53.8 million issued to Seminole's members as a result of a refund Seminole received under a settlement agreement with Florida Power and Light (FPL). Overall demand (MW) sold to members decreased 3.1% as a result of milder weather conditions and a slowing economy experienced during 2001. To recover the revenue shortfall created by lower demands, Seminole billed its member systems approximately $12.6 million under an Interim Rate Rider during the months of October through December 2001. Excluding the effects of the one time rate rebate in 2000, non-fuel revenues increased 0.5% in 2001. Additionally, if the effects of the one time rate rebate in 2000 are excluded, member wholesale cost per kilowatt hour (kWh) increased from 48.8 mills in 2000 to 50.3 mills in 2001. Megawatt hours sold to non-members decreased by approximately 5.8% in 2001 compared to 2000, and prices per kWh decreased by approximately 4.5%. The reduced energy sales to non-members were due to decreasing quantities of power available due to increased member load requirements. The average non-member revenue per kWh decreased in 2001 to 33.9 mills compared to 35.5 mills in 2000. The increase in other revenues during 2001 of approximately $4.5 million is primarily due to the sales of synthetic gypsum.
Fuel and other production expenses increased by 9.7% in 2001 compared to 2000.
The increase in fuel expense is primarily due to a 2.6 % increase in the quantity of fuel consumed as well as a 7.2 % increase in the average cost per ton of fuel purchased in 2001.
The rise in the average cost per ton is attributed to purchases of significantly higher priced spot coal and petcoke in 2001. Other production expenses increased due to longer outage periods in 2001 compared to 2000. Purchased power including transmission increased 20.9 % primarily due to the recording of the FPL settlement refund as a credit to purchased power expense in the year 2000. Excluding the effect of the refund, purchased power and transmission expenses increased 2.1%, reflecting an increase in quantities of power purchased for resale to members and nonmembers. Administrative and General expenses increased due to the amortization of the Walker County judgment and higher legal and consulting charges.
The decrease in net interest expense is due to increased interest charged to construction, primarily associated with the Payne Creek Generating Station (PCGS) project, a 500 megawatt, gas-fired combined cycle generating facility, and decreased variable interest rates, offset by increased interest on the addition of $40.2 million of Rural Utilities Services (RUS) guaranteed long-term debt to reimburse general funds for PCGS construction costs. Non-operating income, net, principally interest income, decreased from 2000 due to lower interest rates on short term investments, and $3.3 million of interest related to the FPL settlement in 2000. Also included in non-operating income is $.9 million from the sale of excess SO, allowances in December 2001. The excess allowances resulted from the efficient operation of the Seminole Generating Station (SGS) and its flue gas desulfurization (FGD) system during 2000 and 2001.
Seminole achieved a net margin of $2.4 million in 2001, which resulted in a Times Interest Earned Ratio (TIER) of 1.05 and a Debt Service Coverage Ratio (DSC) of 1.07.
This marks the nineteenth straight year that Seminole has achieved or exceeded both TIER and DSC objectives.
2 SEMINOLE ELECTRIC COOPERATIVE, INC FINA. NCIAL STATEMENTS 2001
SEMINOLE ELECTRIC COOPERATIVE, INC.
FINANCIAL CONDITION Utility plant, net increased by $39.9 million due to utility plant additions net of retirements of $66.3 million, offset by depreciation of $ 26.4 million. Utility plant additions consisted primarily of construction costs of $61.1 million for the PCGS and other capital improvements to the SGS.
Current assets decreased approximately $49.6 million or 25 percent from 2000.
The cash and cash equivalents balance at the end of the current period of $33.0 million reflects a $13.6 million decrease from the balance at the end of December 2000. Accounts receivable decreased $35.4 million, primarily due to decreased unrecovered fuel adjustment true-up costs. Fuel inventory at the end of 2001 decreased by $1.8 million compared to year end 2000.
The decrease in deferred charges is associated with amortization of approximately
$14.9 million for 2001, relating to the termination of certain coal transportation contracts in December 1998, and $ 6.5 million proceeds from sales of marine equipment, offset by an increase due to the Walker County judgment deferral.
Total equity increased $0.9 million, reflecting current year's net margins of $2.4 million, partially offset by patronage capital credit retirements in 2001, and Other Comprehensive Income (OCI) of $1.0 million. Seminole retired $.5 million in members' patronage capital in 2001, bringing the total-to-date of patronage capital retired to approximately $15.6 million. OCI occurs in 2001 as a result of adopting Statement of Financial Accounting Standards No. 133 (SFAS 133.) Pursuant to SFAS 133, unrealized gains and losses related to changes in the fair value of hedges are recorded in OCI.
Long-term liabilities increased in 2001 from the addition of $40.2 million of RUS guaranteed long-term debt to reimburse general funds for PCGS construction costs, offset by scheduled principal payments of long-term debt and capital leases and capital lease terminations.
Current liabilities decreased in 2001 as a result of a decrease in accounts payable due to the timing of payments at each period end, offset by increases in purchased power invoices for December purchases outstanding at year-end. Other decreases were the payment of the coal transportation contract termination obligation in January 2001, offset by the Walker County judgment liability, an increase in accrued fuel true-up payable, and the current portion of long-term debt.
Deferred credits decreased by $0.5 million in 2001 primarily due to the normal amortization of previously deferred credits, offset by the difference between cash payments and expense recognized related to the operating lease of certain generating facilities.
Working capital at year-end 2001 of $15.3 million was $38.9 million lower than the previous year-end. This decrease in working capital was due to decreases in cash and cash equivalents, accounts receivable and fuel inventory, as well as lower accounts payable, offset by an increase in other accrued liabilities, and the current portion of long-term debt.
Seminole had a current ratio to 1.1 at the end of 2001, and 1.4 at the end of 2000.
Seminole had available uncommitted lines of credit totaling $75 million of which none were drawn at December 31, 2001.
OTHER The PCGS, a 500 megawatt (MW) combined cycle generating facility, began commercial operation on January 1, 2002. Under construction since early 2000, PCGS is located in Hardee County in south central Florida on a site leased from Acuera Corp.,
a wholly owned subsidiary of Seminole.
3 SEMINOLE ELECTRIC COOPERATIVE.
INC.
FINANCIAL STATEMENTS 2001
SEMINOLE ELECTRIC COOPERATIVE, INC.
December 31, 2001 ASSETS Utility plant:
Plant in service.........................................................
Construction work in progress......................................
Less accumulated depreciation and amortization......................................................
Utility plant, net......................................................
Investments:
Investments in associated organizations......................
Funds held by trustees and special funds......................
Total investments.....................................................
Current assets:
Cash and cash equivalents............................................
Receivables, principally for sale of electricity.................................................
Inventories, at average cost:........................................
M aterials and supplies..............................................
Fuel...........................................................................
Prepayments and other..................................................
Total current assets.............................................
Deferred charges.................................................................
838,601,652 235,010,818 1,073,612,470 (390,756,617) 682,855,853 3,918,762 67,395,086 71,313,848 832,917,419 175,429,951 1,008,347,370 (365,344,771) 643,002,599 4,515,036 57,732,797 62,247,833 33,030,974 67,490,466 46,586,838 102,893,051 17,639,968 26,021,004 1,272,484 145,454,896 114,786,672 Total assets..........................................................
1,014,411,269 17,057,179 27,775,174 704,834 195,017,076 116,251,272 1,016,518,780 SEM NOL E FLECTRIC COOPERATIVE, IN FINANCIAL STATEMENTS 2001 2000
SEMINOLE ELECTRIC COOPERATIVE, INC.
December 31, 2001 EQUITIES AND LIABILITIES Equities:
M emberships..............................................................
Patronage capital...........................................................
Donated capital.............................................................
Other margins and equities................................................
Total equities............................................................
Long-term liabilities:..........................................................
Long-term debt..............................................................
Obligations under capital leases...................................
Other.............................................................................
Total long-term liabilities........................................
Current liabilities:
Current portion of:
Long-term debt.........................................................
Obligations under capital leases..............................
Accounts payable..........................................................
Other accrued liabilities................................................
Total current liabilities............................................
Deferred gain on sale-leaseback of plant...........................
Other deferred credits.........................................................
Commitments and contingencies (Notes 10 and 11)
Total equities and liabilities...........................................
1,014,411,269 1,016,518,780 SEMINOLE ELECTRIC COOPERATIVE, INC.
FINANCIAL STATEMENTS 2001 1,000 73,352,675 31,715 (990,383) 72,395,007 778,006,110 548,634 6,838,260 785,393,004 29,649,554 241,521 35,569,235 64,661,533 130,121,843 11,267,160 2000 1,000 71,499,037 31,715 0
71,531,752 770,148,017 790,155 6,245,030 777,183,202 23,306,406 221,997 63,608,155 53,662,243 140,798,801 12,682,929 14,322,096 15,234,255
SEMINOLE ELECTRIC COOPERATIVE, INC.
For the years ended December 31, 2001 Operating revenues.......................................................
Operating expenses:............................................................
Operation:......................................................................
F u el...........................................................................
Other production expenses.....................................
Purchased power.......................................................
Transmission.............................................................
Administration and general....................................
Depreciation and amortization - non-fuel...................
Lease of coal-fired plant................................................
Total operating expenses...............................................
Operating margins before interest expense.......
Interest expense net of amounts capitalized......................
Operating deficits...............................................
Patronage capital credits....................................................
Net operating deficits after interest expense..........................................
Non-operating income:......................................................
Interest income..............................................................
Other income, net.........................................................
Net margins.........................................................
Patronage capital, beginning of year.................................
Patronage capital retirements............................................
669,077,708 174,205,344 59,994,900 299,071,251 31,540,428 21,184,305 26,033,548 28,056,160 640,085,936 582,655,459 158,854,364 54,613,238 239,751,383 33,677,095 17,248,783 25,043,340 28,514,746 557,702,949 28,991,772 24,952,510 32,653,451 (3,661,679) 74,194 (3,587,485) 5,682,927 319,998 2,415,440 71,499,037 (561,802)
Patronage capital, end of year............................................
73,352,675 35,342,519 (10,390,009) 104,101 (10,285,908) 12,130,746 402,371 2,247,209 69,882,439 (630,611) 71,499,037 SEVIND'
.RN F FCTRIC C P
RATI VF.
IN FINANCIAL STATEMENTS 20C1 2000
SEMINOLE ELECTRIC COOPERATIVE, INC.
December 31, 2001 N et m argins.........................................................................
2,415,440 Other comprehensive loss:
Cash flow hedges:
Net loss on derivatives.............................................
(1,872,970)
Less: reclassification adjustment for........................
derivative losses included in net margins...............
882,587 Other comprehensive loss..................................................
(990,383)
Comprehensive income......................................................
1,425,057 2000 2,247,209 0
0 0
2,247,209 SEMINOLE ELECTRIC COOPERATIVE.
INC.
FINANCIAL STATEMENTS 2001
SEMINOLE ELECTRIC COOPERATIVE, INC.
For the years ended December 31, 2001 Cash flows from operating activities:
Net margins.............................................................
Adjustments to reconcile to cash:
Depreciation and amortization................................
Gain on lease/leaseback...........................................
Lease expense/lease payment difference.................
Change in assets and liabilities:
R eceivab les...............................................................
In ven tories................................................................
Prepayments and other............................................
Deferred charges.......................................................
Other long-term liabilities.......................................
Accounts payable.....................................................
Other accrued liabilities..........................................
Total adjustments................................................
Net cash provided by/(used in) operating activities.........................................
Cash flows from investing activities:
Utility plant additions, net of retirements...................
(Purchases of)/proceeds from investments, net............................................................
Net cash used in investing activities.......................
Cash flows from financing activities:
Proceeds from long-term borrowings............................
Payments of long-term debt..........................................
Payments of capital lease obligations...........................
Payments of patronage capital credits..........................
Net cash provided by financing activities..............
Net decrease in cash and cash equivalents........................
Cash and cash equivalents, beginning of year..................
Cash and cash equivalents, end of year........................ $
Supplemental disclosure: Interest paid.......................... $
2,415,440 2,247-209 45,033,747 (1,168,024) 1,051,594 38,904,608 (1,168,023) 2,158,951 35,402,585 1,171,381 (567,650) 4,830,580 (157,665)
(28,038,920)
(11,750,142) 45,807,486 (73,144,843)
(5,715,313)
(89,614)
(17,254,026)
(32,087) 32,811,606 4,214,399 (19,314,342)
_*_7*0671*,3)
(66,317,682)
(6,810,740) 7 3 J18 214~
(147,818,674) 48,686,583 (99,132,091) 100,000,000 (21,336,679)
(17,569,648)
(630,611) 60,463,062 40,205,000 (28,071,569)
(221,997)
(561,802) 11,349,632 (13,555,864) 46,586,838 33,030,974 (55,736,162) 46,586,838 35,746,181 4_684,83 FINANCIA L STATEMENTS 2,01 2000 48,222,926
SEMINOLE ELECTRIC COOPERATIVE, INC.
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. 1 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. The 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).
At December 31, 2001, 175 employees or approximately 38% of the total workforce were covered by a four year collective bargaining agreement with Utility Workers Union of America expiring on June 30, 2003.
Seminole holds a 1.6994% undivided ownership interest in the Crystal River Unit No. 3 (CR3) nuclear power plant operated by Florida Power Corporation (FPC). 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 9
SEMINOLE ELECTRIC COOPERATIVE INC FINANCIAL STATEMIENTS 2001
SEMINOLE ELECTRIC COOPERATIVE, INC.
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 sexveral members and the Southeastern Power Administration, which provides less than 1% of the total energy required by all members.
Operating rev enue consists primarilv of sales of electric power and energy by Seminole and a facilities use charge for Seminole's transmission lines serving a single member cooperative. Member revenues include amounts resulting from a fuel and purchased power adjustment clause which pros ides for billings to reflect increases or decreases in fuel and fuel related purchased power costs. The levelized adjustment factor is based on costs projected by Seminole for a twelve month period. Any over-recosery 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 ox er-recoveries may be deferred with interest esery six months until such time as the member elects to have the os'er-recovery including accumulated interest refunded. Os er-recoveries of approximately $8.9 million and under recoveries of approximately $35.0 million at December 31, 2001, and 2000, respectiv'ely, are recorded in accrued liabilities or accounts receixable until refunded or billed.
Included in operating revenue are approxinately $651 million and $568 million of revenuie from members for the years ended December 31, 2001 and 2000, respectively, of which approximately $64 million and $63 million primarily related to December sales are included in receivables at December 31, 2001 and 2000, respectively. During 2000, as a result of a settlement agreement with a power supplier, Seminole received a refund of $50.5 million plus interest from January 1, 2000 (see Note 11). A rate rebate in an amount equal to this refund including interest received svas distributed to Seminole's meinbers pursLlant to a rate rider adopted by Seminole's Board of Trustees, and is reflected as a reduction to revenue from members, for the year ended December 31, 2000.
Utility Plant Utility plant owned by Seminole is stated at original cost. Such cost includes applicable supersisory and oserhead cost, plus net interest charged during construction. The amounts of interest capitaliced during 2001 and 2000 were approximately $10.8 million and $5.6 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 remos al, net of any salvage value, 10 S
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SEM INOLE ELECTRIC COOPERATIVE, INC.
is charged to accumulated depreciation. 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 2001 and 2000 were as follows:
2001 2000 Coal-fired production plant 3.10%
3.10%
Transmission plant 2.75%
2.75%
General plant 8.05%
7.53%
Nuclear production plant 4.51%
4.51%
Depreciation expense amounted to approximately $24.3 million and $23.9 million for 2001 and 2000, 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 7.07% and 7.0% for 2001 and 2000, respectively.
Amortization of leased assets under capital leases amounted to approximately
$0.2 million and $0.7 million in 2001 and in 2000, respectively. Of these amounts,
$0.5 million in 2000 relating to certain marine transportation equipment capital leases terminated in 2000, was recorded in deferred charges (see Note 11).
Amortization of Deferred Gain 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 expense for 2001 and 2000 was $1.4 million and $1.5 million respectively.
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 $26.9 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 Charges At December 31, 2001 and 2000, deferred charges included unamortized debt costs and related refinancing premiums of approximately $39.0 million and $41.4 million, respectively. These deferred charges will be recovered through rates over the remaining lives of the related debt ranging up to nineteen years. In 2001,the 11 SEMINOLE ELECTRIC COOPERATIVE, INC.
FINANCIAL STATEMENTS 2001
SEMINOLE ELECTRIC COOPERATIVE, INC.
Seminole Board of Trustees authorized the implementation of an expense deferral plan pursuant to the provisions of SFAS No. 71, relating to the Walker County judgment (see Note 11). The amount of the judgment, including post judgment interest has been deferred and is being amortized and recovered through rates charged to members over a 60 month period, starting in July 2001. 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 coal transportation contract terminations (see Note 11). Anticipated marine equipment lease termination costs, operating costs of the leased marine equipment subsequent to coal transportation contract terminations, and certain other costs aggregating approximately $85.0 million have been deferred pursuant to this plan. Included in these costs is the net book value of approximately $6.5 million and $8.2 million in 2001 and 2000, respectively, relating to marine transportation equipment under capital leases terminated during 2000. 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 teriminated.
Amortization of deferred costs associated with the coal transportation contract terminations was approximately $14.9 million anid $11.9 million in 2001 and 2000, respectively. Amortization of other deferred charges amounted to approximately
$2.6 million in 2001 and 2000.
Long-Lived Assets Seminole evaluates, on a reglular 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, 2001, the net utility plant and net Ulnam(ortized deferred charges balances are not considered to be impaired.
Deferred Credits At December 31, 2001 and 2000, deferred credits primarily included deferred lease expense swhich 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. These deferred credits have been authorized by the Board of Trustees.
Accounting for Derivatives and Hedging Activities Seminole adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities", as amended by Statement of Financial Accounting Standards No. 137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement No. 133", an amendment of FASB Statement No. 133, and Statement of Financial Accounting Standards No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities", an amendment of FASB Statement No. 133 (referred to hereafter as "SFAS 133"), on January 1, 2001. Seminole did 12 FiNANCIAL IATENENTS 20 1
SEMINOLE ELECTRIC COOPERATIVE, INC.
not have any derivatives as defined in the standard on January 1, 2001 and accordingly did not record a transition adjustment.
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 SPAS 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 in 2001. These transactions are designated as cash flow hedges and are deemed to be highly effective, and therefore no ineffective losses were recognized in earnings for 2001. For the year ended December 31, 2001, net losses of $0.9 million were reclassified into earnings and are included in "Other income, net" in the Consolidated Statement of Revenue and Expenses and Patronage Capital. Other Comprehensive Income reflects a $0.6 million loss related to these transactions in 2001 which will be reclassified into earnings each month in 2002, when the gas is purchased. The entire $0.6 million is expected to be reclassified into earnings within the next twelve months.
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. At December 31, 2001, this interest rate swap was deemed highly effective, and therefore no ineffective losses were recognized in earnings for 2001. On January 8, 2002, the lowering of the credit rating of National Rural Utilities Cooperative Finance Corporation (CFC), the Guarantor of the bonds resulted in an alternative index rate being used prospectively to derive the variable interest rate in the swap. This will result in an ineffective portion of the swap to occur prospectively. The $0.4 million loss reported in Other Comprehensive Income will be reclassified into earnings each month for the next two years, when the pollution control revenue bond interest is incurred.
Cash Equivalents Seminole considers all short term, highly liquid investments with an original maturity of three months or less to be cash equivalents.
13 SEMINOLE ELECTRIC COOPERATIVE, INC.
FINANCIAL STATEMENTS 2001
SEMINOLE ELECTRIC COOPERATIVE, INC.
NOTE 3 UTILITY PLANT:
Owned property:
Coal fired production plant Transmission plant General plant Nuclear plant, including fuel Transportation equipment under capital leases Leasehold improvements of coal-fired production plant Construction work in progress Decemulber 31, 2001
$ 610,358,709 156,564,596 22,307,224 23,085,213 812,315,742 2,538,591 23,747,319 838,601,652 235,010,818 1,073,612,470 2000
$610,441,048 156,548,208 21,241,107 22,273,734 810,504,097 2,538,591 19,874,731 832,917,419 175,429,951 1,008,347,370 Accumulated depreciation and amortization:
Owned property
( 378,602,331)
Leased transportation equipment (1,846,950)
Leasehold improvements (10,307,336)
(390,756,617) 682,855,853 (355,115,962)
(1,616,989)
(8,611,820)
(365,344,771) 643,002,599 NOTE 4 INVESTMENTS:
December 31, Investments in associated organizations:
2001 2000 CFC:
Membership Capital term certificates Subordinated term certificates Patronage capital certificates Other 1,000 1,448,731 1,912,375 547,048 9,608 3,918,762 1,000 1,451,561 2,498,473 552,394 11,608 4,515,036 Funds held by trustees and special funds:
Pollution control bond funds 15,088,417 Nuclear decommissioning trust fund 4,708,916 Lease termination fund 40,621,734 Walker County judgment escrow fund 6,976,019 67,395,086 14,889,550 4,556,500 38,286,747 0
57,732,797 SEM N0LE
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I N F INA N CI A L S T A TEMEN TS 2 0 01 14
SEMINOLE ELECT R'I"C COOPERATIVE, INC.
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, $1,448,731 are required as a condition of membership and of loans provided to Seminole by CFC. Of the approximately $1.4 million and
$1.5 million carrying amounts at December 31, 2001 and 2000, respectively,
$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 $103,017 in 2001 and $105,847 in 2000, 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 6.1% and 6.3% at December 31, 2001 and 2000, respectively.
At December 31, 2001 and 2000, the estimated fair values of these investments of approximately $1.9 million and $2.4 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 for rate-making purposes. At December 31, 2001 and 2000, the estimated fair values of these funds of approximately $20.1 million and $19.4 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.
The Walker County judgment escrow fund, which has been invested in a United States short-term Treasury bill with a yield of 1.522%, will be held to maturity. At December 31, 2001, the estimated fair value of this fund of approximately $6,975,623 is based on quoted market prices for the securities held by the escrow agent.
15 SEMINOLE ELECTRIC COOPERATIVE, INC.
FINANCIAL STATEMENTS 2001
SEMINOLE ELECTRIC COOPERATIVE, INC.
NOTE 5 LONG-TERM LIABILITIES:
Long-Term Debt 2001 First mortgage notes payable to Federal Financing Bank (FFB),
guaranteed by RUS, principal due in various installments through 2020, interest at fixed rates, from 4.634% to 7.295%
First mortgage notes payable to RUS, principal due in various installments through 2019, interest at 5.00%
Pollution control revenue bonds payable to the Putnam County Develo ment Authority, guaranteed by CFC, principal due in various installments through 2014, interest at adjustable rates, currently 2.99% and 2.40%
First mortgage notes payable to CFC, principal due in various installments through 2019, interest at adjustable rates, currently 4.70%
Lease termination obligation payable to State Street Bank and Trust at maturity in 2020, interest imputed at a fixed rate of 3.05%
Less current portion December 31, 2000 597,509,978 580,250,090 6,802,599 125,300,000 8,104,998 69,938,089 807,655,664 (29,649,554) 778,006,110 7,093,927 129,850,000 8,390,127 67,870,279 793,454,423 (23,306,406) 770,148,017 The estimated maturities and annual sinking find requirements of all long term debt, at interest rates as of December 31, 2001 for the four years subsequent to December 31, 2002, are presented below:
Year ending December 31, 2003 2004 2005 2006 Annual Maturities and Sinking Fund Requirements S
31,547,511 33,330,753 35,735,452 38,100,634 During Novsember and December, 2000, FFB debt in the amount of
$100 million was advanced to Seminole at a weighted average interest rate of 5.66%. During 2001, FFB debt in the amuount of $40,205,000 wis advanced 16 i [ V
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SEMINOLE ELECTRIC COOPERATIVE, INC.
to Seminole at a weighted average interest rate of 5.14%. At December 31, 2001, approximately $39.8 million of RUS approved loan funds remained available for Seminole to draw pending Seminole meeting RUS requirements for receiving the funds.
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, 2001 and 2000, the estimated fair value of long-term debt including current portion but excluding the lease termination obligation, is approximately $775 million and $747 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 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, 2001, 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, 2001:
Year ending December 31, 2002 304,461 2003 304,461 2004 304,460 2005 0
2006 0
Thereafter 0
Total minimum lease payments 913,382 Less amount representing interest (123,227)
Present value of minimum lease payments 790,155 Less current principal portion (241,521) 548,634 This transportation equipment lease provides for renewal and option to purchase the equipment at fair market value at various dates or upon expiration.
During 2001 and 2000, 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.
17 EMINOLE ELECTRIC COOPERATIVE INC.
FINANCIAL STATEMENTS 2001
SEMINOLE ELECTRIC COOPERATIVE, INC.
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 generalxv to twenty five percent of patronage capital and margins of the next preceding year where, after giving effect to such distribution, the total equitx will equal or exceed twenty percent of total assets. Distributions mnax be made, however, in such amiotints as may be approved by RUS through waiver of the aforementioned restrictions. Such distributions to members totaled $561,802 and
$630,611 in 2001 and 2000, respectively, representing amounts equal to 25% of 2000 and 1999 net margins, respectively. The RUS mortgage requires Seminole to design its wholesale rates with a view towards maintaining, on a calendar sear 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 2001 and 2000, Seminole achieved a Times interest Earned Ratio of 1.05, andi a Debt Service Coverage Ratio of 1.07 and 1.08, respectively.
NOTE 7 LINES OF CREDIT:
Seminole has available tiiscomisiitted lines of credit totaling $75 million of which none wvere drawn at December 31, 2001 and 2000. RUS policy governs Use of these fuids.
NOTE 8 INCOME TAXES:
Seminole is a nion-exempt cooperative subject to federal and state income taxes and files a consolidated tax return. As a cooperative, Seminiole is entitled to exclude patronage dividends frois taxable incomne. Semiinoles bylaxvs 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 inensber-patrons. Accordingly, such income will not be subject to income taxes.
Seminole's rate-making methods prostide that any incomne 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 redluction of taxes currently payable in the period utilized. In 2001 and 2000, net operating losses of approximately $0.7 million and $3.0 msillion, respectively, were generated from non-patronage activity. At December 31, 2001, niet operating losses and investment tax credits of approximately $97.7 million and $73,000 are available to offset future taxable income and tax liabilities, respectively, expiring in years throuigh 2021. Furthermore, alternative miniisimtim tax (AMT) credits of approximatelx
$2.5 million, which do not expire, are available to offset regilar income tax liabilities.
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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 2001 and 2000:
2001 2000 Noncurrent deferred tax asset 39,300,000 53,900,000 Less valuation allowance (39,300,000)
(47,500,000)
Net noncurrent deferred tax asset 6,400,000 Noncurrent deferred tax liability 6,400,000 Net noncurrent deferred tax asset/liability
-0 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.
The noncurrent deferred tax asset reflects deductible temporary differences and net operating loss carryforwards at statutory rates plus investment tax credits and AMT credits. Based on Seminole's historical transactions and the exclusion of patronage dividends 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, 2001. 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 2000 to 2001 due to the expiration of net operating loss carryforwards and investment tax credits. The noncurrent deferred tax liability reflects taxable temporary differences at statutory rates.
NOTE 9 EMPLOYEE BENEFITS:
Substantially all Seminole employees participate in the National Rural 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. Seminole's contributions amounted to approximately $3.0 million in 2001 and $2.6 million in 2000. 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. Seminole also has a retirement savings plan for all employees that is qualified under Section 401(k) of the Internal Revenue Code.
Seminole's contributions under the savings plan are based upon specified percentages of employee contributions and were approximately $636,000 and
$631,000 for the years ended December 31, 2001 and 2000, respectively.
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 19 SEMINOLE ELECTRIC COOPERATIVE,
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SEM INOLE ELECTRIC COOPERATIVE, INC.
expense, health care coverage tinder Seminole's group plan. In addition, these retirees may use a portion of their accumulated unused sick pay to apply tow ard 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, 2001 and 2000, The plan is funded on a pay-as-y'ou-go basis.
Accumulated postretirement benefit obligation (APBO):
2001 Active plan participants not yet fully eligible Fully eligible active plan participants Retirees and dependents Other plan participants Total APBO Unrecognized gain/(loss) from past experience Unrecognized prior service cost Accrued postretirement benefit liability Net periodic postretirement benefit co included the following components Service cost Interest cost on accumulated benefit obligation Amortization of actuarial gain Amortization of prior service cost Net periodic postretirement benefit cost 2000 2,889,000 3,707,500 1,195,800 374,800 44,400 4,504,000 1,116,000 358,600 5,978,600 540,700 324,000 33,000 4,605,200 940,300 0
5,545,500 299,600 315,700 309,400 311,600 (48,400)
(38,100)
(6,800) 0 553,800 3
589,200 A 9.0% increase in the cost of covered health care benefits was assumed for 2001. This rate is assumed to decrease incrementally to 5.5% in 2008 and remain at that level thereafter. The health care cost trend rate assumption has a significant effect on the amounts reported. For example, a 1 (6 increase in the health care trend rate would increase the accumulated postretirement benefit obligation by $290,100 or 6.4(X% at year-end 2001 and net periodic cost by $40,300 or 7.1 9% for the year. The weighted average discount rate and rate of compensation increase used in determining the accumulated post-retirement benefit obligation for 2001 were 7.25% and 4.5%, respectivel. The net effect of changes in assumptions for health care cost trend ratesand weighted average discount rate caused a decrease in the APBO at December 31, 200 1. The unrecognized net gain in excess of ten percent of the APBO is being amiortized over the fifteen remaining service years of active plan participants, in the amount of $48,400 per year.
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NOTE 10 OPERATING LEASES:
At December 31, 2001, 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, 2002 36,280,609 2003 36,972,745 2004 37,656,481 2005 38,334,217 2006 38,522,028 Thereafter 113,306,962 These leases generally provide for renewals 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 $1.8 million and $0.7 million in 2001 and 2000, respectively. These payments were included as a cost of fuel inventory and expensed based on the tons of coal burned throughout the year. Marine transportation equipment lease payments of approximately $2.6 million in 2000, were recorded to deferred charges (see Notes 2 and 11).
NOTE 11 COMMITMENTS AND CONTINGENCIES:
Seminole is purchasing a significant portion of the coal for Seminole Units No.
1 and No. 2 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 $51.0 million and $58.7 million in 2001 and 2000, respectively.
In 1999 and 2000 Seminole entered into settlement agreements with each of three coal transportation contract suppliers which provide for the termination of all contractual relationships between the parties as of the respective date of discontinuance of services. Under the terms of these agreements Seminole made settlement payments to each of the parties, the amounts of which are subject to confidentiality agreements. These amounts have been included in deferred charges pursuant to the SFAS No. 71 expense deferral plan (see Note 2). These settlement agreements also provide for the dismissal of all litigation between the parties with prejudice. During 1999 Seminole gave notice to the lessors of certain leased marine transportation equipment of its intent to terminate these leases under the provisions of the lease agreements for economic reasons. Such terminations were completed during 2000 and the costs of termination have been deferred pursuant to the SFAS No. 71 expense deferral plan.
On January 4, 1999, Seminole began coal shipments utilizing lower cost all-rail transportation under a new agreement with CSX, having a minimum term of six years. Seminole is required to transport a significant portion of its coal and petcoke 21 SEMINOLE ELECTRIC COOPERATIVE, INC.
FINANCIAL STATEMENTS 2001
SEMINOLE ELECTRIC COOPERATIVE, INC.
to be received at Scminole Unit No. I mnd Unit No. 2 under this agtrceent. Total chirgcs under this contrict were i1pproxiliiatel\\ $62.9 imijillion aind 553.1 imillion in 2001 and 2000, respecti ely.
Seminole has established an1. external NDTF in compliance with -egulations prescribed by the Nuclear Regulatori Commission. The trust tunrrd balance COf approxirimtely $4.7 million represents Seminole's cucmtilitive shaire,it December 31, 2001 of the estimated sinking fund reserxve repluihed to decommission CR3. Annual cash deposits Will continue to be nmide to the NDITF representing Seminole's annual shaie of the projected sinking ftond requiremncrts. These amoinrits will be recovered from members through rates annually. Baised upon a site specific stud\\
completed in 2000, Seminole's total share of the projected cost of decommissioining is approximately $8.8 million stat Ied in 2000 dollars, Mnd decoiitiiissionin" expenditures are expected to occur over a twerity-six y eai period ending in the year 2041.
Seminocle has lorg term contracts foti the transportation of natural g'as for the PCGS begimning in 2002 and terminating in 2020. These contircts require annual minimlum take-or-pay capaicitv payments for the next five Nears of S10.4 million in 2002 and $13.2 million in each of 2003 throu'Lh 2006.
Seminole has various firm conttacts with suppliers for puirchased pow(ei with remaining terms rangirng from cine to folurteen y~ears. These contracts requiire amnuti 1 minimum take-or-pay capacitx payiments tor the next five yealrs is follcos:
Year ending December 31, 2002 79.9 million 2003 76.3 million 2004 96.0 million 2005 107.3 million 2006 108.0 million Total charges, including capacity pax merits, under these contracts were
ýipproxim* iely $226.4 million mnd 5226.6 million for 2001 and 2000, respectively.
On June 26, 2001, the Circuit Court of Walker County, A.ahibam entered a judgment againsr Seminole in the amount of....
million is ci resuilt of the jury's verdict in litigation filed in 1998 regarding a dispute under a cerrain spot coali contract. Post judgment interest on this 'amtiount accrues rit 12-,K, simple interest.
Post trial motions to set aside or reduce the judgmenIt were filed on behalf of Seminole. On October 24, 2001, the trial judge entered an 0rdIcFer denying all tOf the post trial mcotions. Seminole filed its Notice of Appeil with the Alabima Supreme Court on October 25, 2001. Seminole has posted a supcrsedcis bond with the court Which Will stay execCutioin of the judgment during the iappeal process. Seminole believes that this dispute wxill ultimately be resolved in its ftaxor. In the interim, pursuant to an expense deferral plan developed in accordtince xxith the provisions of SFAS No. 71 and adopted by Seminole's Board of Trustees, the amccunt of the judgment, inicluding accricied post judgmenrt iirteiest, has been deferred inid is being amcorti ed and recovered through rates charged to iiembers over a 60-month period starting in July 2001. As a coinsideration cit oobtiining the supeisedeas bond, 22 8,* !A N C' I f I t I
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Seminole established an escrow account with an initial deposit of $5 million, to which monthly deposits will be made equal to the amounts collected through rates pursuant to the SFAS No. 71 expense deferral plan. The amount of the judgment, including accrued post judgment interest, has been reflected in "Other accrued liabilities." "Deferred charges" reflects the deferral of this amount, net of accumulated amortization charged to expense.
In the normal course of business Seminole has ongoing disputes with some of its power suppliers. Additionally, some of the billings received by Seminole for purchased power are subject to adjustment based on the actual costs of the seller.
During 2001 and 2000, several disputes were settled resulting in refunds relating to purchased power costs recorded in prior periods totaling approximately $0.4 million and $51.9 million, respectively, not including interest. Also during 2001 and 2000, refunds were received in the aggregate amounts of approximately $1.6 million and
$1.9 million, respectively, not including interest, for adjustments to reflect actual costs related to power billings from prior periods. These amounts were recorded in both years as reductions to purchased power expenses.
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 significantly affect Seminole's financial statements.
23 SEMINOLE ELECTRIC COOPERATIVE, INC.
FINANCIAL STATEMIENTS 2001
REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS PRICEWATERHOUsEqCOPERS 0 To the Board of Trustees Seminole Electric ('ooperative, Inc.
In our opinion, the accompany ing consolidated balance sheets and the related consolidated statements of reverIue and expenses and patironage capital, of comprehensive income and of cash flows present tiirly, in all material respects, the financial position of Seminole Electric C.ooperative, Inc. and its subsidiaries
("Seminole") at I)ecember 31, 2001 and 2000, and the results of their operations and their cash flows for the vears then crIeded in conformity With accounting principles generally accepted in the United States of America. These financial statements are the responsibility Of Seminole's management; ouir responsibility is to express an opinion on these financial statements based on our andits.
We conducted our audits of these statements in accordance with auditinc standards generally accepted in the United States of America and the standards applicable to financial audits contained in Guireminent Auditing Staoudcuds issued by the Comptroller General of the United States. These standards reqnire that we plan and perform the audit to obtain reasonable assurance about wihether the financial statements are ftee 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 c\\ aluating the overall financial statement presentation. We believe that out audits provide a iea;sonable basis for outr opinion.
As discuIssed in Note 2 to the financial statements, Seminole adopted the provisions of Financial Accounting Standards Statement No. 1 33, Accounting fur Derivati've Instruments 6ind Hedging, on Janriai s 1, 2001.
In accordance with Governmient Auditing Stimdards, x\\ e have also issued a report dated February 22, 2002, on our consideration of Seminole's internal control over financial reporting and on our tests of its compliance with certain provisions of laws, regulations and contracts. That report is an integral part of an audit perforrmed in accordance with Government Auditing Standards and should be read in conjunction with this report in considering the tresults of our audit.
February 22, 2002 24 S w '.l 1 N 52 I
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