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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-Q
(Mark One)
[X](MARK ONE)
[ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 1998FOR THE QUARTERLY PERIOD ENDED MARCH 31, 1999
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the transition period fromFOR THE TRANSITION PERIOD FROM ___________ toTO _____________
Commission File No.COMMISSION FILE NO. 33-7591
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Oglethorpe Power Corporation
(An Electric Membership Corporation)OGLETHORPE POWER CORPORATION
(AN ELECTRIC MEMBERSHIP CORPORATION)
(Exact name of registrant as specified in its charter)
GeorgiaGEORGIA 58-1211925
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(State or other jurisdiction of (I.R.S. employer
incorporation or organization) identification no.)
Post Office BoxPOST OFFICE BOX 1349
2100 East Exchange Place
Tucker, GeorgiaEAST EXCHANGE PLACE
TUCKER, GEORGIA 30085-1349
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (770) 270-7600
Indicate by check mark whether the registrant: (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes /X/ No / /
---- ----YES X NO
Indicate the number of shares outstanding of each of the registrant's
classes of common stock, as of the latest practicable date. The Registrant is a
membership corporation and has no authorized or outstanding equity securities.
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------THE REGISTRANT IS A
MEMBERSHIP CORPORATION AND HAS NO AUTHORIZED OR OUTSTANDING EQUITY SECURITIES.
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OGLETHORPE POWER CORPORATION
INDEX TO QUARTERLY REPORT ON FORM 10-Q
FOR THE QUARTER ENDED SEPTEMBER 30, 1998MARCH 31, 1999
Page No.
--------PAGE NO.
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
Condensed Balance Sheets as of September 30, 1998March 31, 1999 (Unaudited)
and December 31, 19971998 3
Condensed Statements of Revenues and Expenses and
Comprehensive Margin (Unaudited) for the Three Months
Ended March 31, 1999 and Nine Months Ended September 30, 1998 and 1997 5
Condensed Statements of Cash Flows (Unaudited)
for the NineThree Months Ended September 30,March 31, 1999 and 1998 and 1997 6
Notes to the Condensed Financial Statements 7
Item 2. Management's Discussion and Analysis of
Financial Condition and Results of Operations 8
Item 3. Quantitative and Qualitative Disclosures About
Market Risk 17
PART II - OTHER INFORMATION
Item 5. Other Information 18
Item 6. Exhibits and Reports on Form 8-K 1718
SIGNATURES 1819
2
PART I - FINANCIAL INFORMATION
ItemITEM 1. Financial Statements
Oglethorpe Power Corporation
Condensed Balance Sheets
September 30, 1998 and December 31, 1997FINANCIAL STATEMENTS
OGLETHORPE POWER CORPORATION
CONDENSED BALANCE SHEETS
MARCH 31, 1999 AND DECEMBER 31, 1998
- --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
(dollars in thousands)
1999 1998
1997
AssetsASSETS (Unaudited)
--------------------------------------------------------------------------
Electric plant, at original cost:ELECTRIC PLANT, AT ORIGINAL COST:
In service $4,900,356 $4,910,067$4,856,328 $4,856,174
Less: Accumulated provision for depreciation (1,496,228) (1,412,287)
---------- ----------
3,404,128 3,497,780(1,541,274) (1,510,888)
------------------- ------------------
3,315,054 3,345,286
Nuclear fuel, at amortized cost 83,310 90,42386,918 84,418
Construction work in progress 17,410 13,578
---------- ----------
3,504,848 3,601,781
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Investments and funds:25,365 20,948
------------------- ------------------
3,427,337 3,450,652
------------------- ------------------
INVESTMENTS AND FUNDS:
Decommissioning fund, at market 107,699 105,817122,287 122,094
Deposit on Rocky Mountain transactions, at cost 54,845 52,17656,695 55,755
Bond, reserve and construction funds, at market 32,934 33,16032,229 32,909
Investment in associated organizations, at cost 15,597 15,94016,093 16,231
Other, at cost 4,940 4,641
---------- ----------
216,015 211,734
---------- ----------
Current assets:3,302 3,326
------------------- ------------------
230,606 230,315
------------------- ------------------
CURRENT ASSETS:
Cash and temporary cash investments, at cost 71,905 63,21588,766 106,235
Other short-term investments, at market 103,586 97,022
Receivables 127,242 105,99374,227 73,356
Customer receivables 104,030 110,919
Notes and interim financing receivable 93,850 45,151
Inventories, at average cost 74,916 65,52883,459 76,783
Prepayments and other current assets 20,501 12,530
---------- ----------
398,150 344,288
---------- ----------
Deferred charges:26,291 21,395
------------------- ------------------
470,623 433,839
------------------- ------------------
DEFERRED CHARGES:
Premium and loss on reacquired debt, being amortized 211,136 196,583208,766 206,729
Deferred amortization of Scherer leasehold 98,657 96,30399,807 99,297
Discontinued projects, being amortized 34,157 36,203
Deferred debt expense, being amortized 16,842 15,34515,573 15,825
Other 39,462 43,823
---------- ----------
366,097 352,054
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$4,485,110 $4,509,857
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---------- ----------38,795 33,405
------------------- ------------------
397,098 391,459
------------------- ------------------
$4,525,664 $4,506,265
------------------- ------------------
------------------- ------------------
The accompanying notes are an integral part of these condensed financial
statements.
3
Oglethorpe Power Corporation
Condensed Balance Sheets
September 30, 1998 and December 31, 1997
OGLETHORPE POWER CORPORATION
CONDENSED BALANCE SHEETS
MARCH 31, 1999 AND DECEMBER 31, 1998
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(dollars in thousands)
1999 1998
1997
Equity and LiabilitiesEQUITY AND LIABILITIES (Unaudited)
------------------------------------------------------------------------
Capitalization:CAPITALIZATION:
Patronage capital and membership fees (including unrealized gain (loss) of $2,854$231 at
September 30, 1998March 31, 1999 and ($107)$1,006 at December 31, 19971998 on available-for-sale
securities) $342,775 $ 330,509$360,025 $352,701
Long-term debt 3,183,280 3,258,0463,138,821 3,177,883
Obligation under capital leases 283,958 288,638280,530 282,299
Obligation under Rocky Mountain transactions 54,845 52,176
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3,864,858 3,929,369
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Current liabilities:56,695 55,755
----------------- -----------------
3,836,071 3,868,638
----------------- -----------------
CURRENT LIABILITIES:
Long-term debt and capital leases due within one year 96,483 89,556102,921 97,475
Accounts payable 57,736 46,676
Notes payable 3,982 --
Accounts payable 69,785 51,10390,884 50,986
Accrued interest 14,415 12,96114,405 10,074
Accrued and withheld taxes 17,154 5176,484 214
Other current liabilities 4,742 8,428
--------- ---------
206,561 162,565
--------- ---------
Deferred credits and other liabilities:6,343 17,901
----------------- -----------------
278,773 223,326
----------------- -----------------
DEFERRED CREDITS AND OTHER LIABILITIES:
Gain on sale of plant, being amortized 58,900 60,756
Net benefit of Rocky Mountain transactions, being amortized 89,986 92,37557,663 58,282
Net benefit of sale of income tax benefits, being amortized 28,032 34,03924,028 26,030
Net benefit of Rocky Mountain transactions, being amortized 88,393 89,189
Accumulated deferred income taxes 63,117 63,11763,203 63,203
Decommissioning reserve 146,122 142,354155,795 156,021
Other 27,534 25,282
--------- ---------
413,691 417,923
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$4,485,110 $4,509,857
--------- ---------
--------- ---------21,738 21,576
----------------- -----------------
410,820 414,301
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$4,525,664 $4,506,265
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----------------- -----------------
The accompanying notes are an integral part of these condensed financial
statements.
4
Oglethorpe Power Corporation
Condensed Statements of Revenues and Expenses and Comprehensive Margin
(Unaudited)
For the Three and Nine Months Ended September 30, 1998 and 1997
OGLETHORPE POWER CORPORATION
CONDENSED STATEMENTS OF REVENUES AND EXPENSES AND COMPREHENSIVE MARGIN
(UNAUDITED)
FOR THE THREE MONTHS ENDED MARCH 31, 1999 AND 1998
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(dollars in thousands)
Three Months Ended September 30, Nine Months Ended September 30,1999 1998
1997 1998 1997
-------------------------------- -------------------------------------------------------------------------------------
Operating revenues:OPERATING REVENUES:
Sales to Members $ 331,361 $ 280,503 $ 860,317 $ 767,714$245,043 $231,943
Sales to non-Members 14,414 6,076 37,451 33,226
--------- --------- --------- ---------
Total operating revenues 345,775 286,579 897,768 800,940
--------- --------- --------- ---------
Operating expenses:5,721 3,324
--------------- ---------------
TOTAL OPERATING REVENUES 250,764 235,267
--------------- ---------------
OPERATING EXPENSES:
Fuel 55,680 61,206 144,525 152,79941,535 39,867
Production 49,996 43,418 145,413 134,49050,311 46,932
Purchased power 153,202 95,038 337,907 215,35063,006 54,564
Depreciation and amortization 31,074 30,154 93,273 96,534
Other operating expenses -- 10 -- 5,775
--------- --------- --------- ---------
Total operating expenses 289,952 229,826 721,118 604,948
--------- --------- --------- ---------
Operating margin 55,823 56,753 176,650 195,992
--------- --------- --------- ---------
Other income (expense)33,619 31,123
--------------- ---------------
TOTAL OPERATING EXPENSES 188,471 172,486
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OPERATING MARGIN 62,293 62,781
--------------- ---------------
OTHER INCOME (EXPENSE):
Interest income 5,742 7,247 21,856 21,0027,455 7,840
Amortization of net benefit of sale of income tax benefits 2,799 2,799 8,396 8,3962,798
Allowance for equity funds used during construction 19 32 49 8127 22
Other 786 457 1,699 4,025
--------- --------- --------- ---------
Total other income 9,346 10,535 32,000 33,504
--------- --------- --------- ---------
Interest charges:810 125
--------------- ---------------
TOTAL OTHER INCOME 11,091 10,785
--------------- ---------------
INTEREST CHARGES:
Interest on long-term-debtlong-term debt and other obligations 65,256 68,488 199,797 216,29465,745 66,145
Allowance for debt funds used during construction (173) (328) (452) (873)
--------- --------- --------- ---------
Net interest charges 65,083 68,160 199,345 215,421
--------- --------- --------- ---------
Net margin (loss) 86 (872) 9,305 14,075(460) (205)
--------------- ---------------
NET INTEREST CHARGES 65,285 65,940
--------------- ---------------
NET MARGIN 8,099 7,626
Net change in unrealized (loss) gain on
available-for sale securities 2,366 787 2,961 329
--------- --------- --------- ---------
Comprehensive margin $ 2,452 ($ 85) $ 12,266 $ 14,404
--------- --------- --------- ---------
--------- --------- --------- ---------(775) 229
--------------- ---------------
COMPREHENSIVE MARGIN $7,324 $7,855
--------------- ---------------
--------------- ---------------
The accompanying notes are an integral part of these condensed financial
statements.
5
Oglethorpe Power Corporation
Condensed Statements of Cash Flows (Unaudited)
For the Nine Months Ended September 30, 1998 and 1997
OGLETHORPE POWER CORPORATION
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
FOR THE THREE MONTHS ENDED MARCH 31, 1999 AND 1998
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(dollars in thousands)
1999 1998
1997
--------- -----------------------------------------------------
Cash flows from operating activities:CASH FLOWS FROM OPERATING ACTIVITIES:
Net margin $ 9,3058,099 $ 14,075
--------- ---------
Adjustments to reconcile net margin to net cash provided by operating
activities:7,626
------------ -----------------
ADJUSTMENTS TO RECONCILE NET MARGIN TO NET CASH
PROVIDED BY OPERATING ACTIVITIES:
Depreciation and amortization 136,151 139,190
Net benefit of Rocky Mountain transactions -- 22,470
Deferred gain from Corporate Restructuring -- 4,67036,186 43,554
Allowance for equity funds used during construction (49) (81)(27) (22)
Amortization of deferred gains (1,856) (1,823)(619) (619)
Amortization of net benefit of sale of income tax benefits (8,396) (8,396)(2,799) (2,798)
Other 9,991 3,268
Change in net current assets, excluding long-term debt and capital leases due
within one year and notes payable:3,269 4,206
CHANGE IN NET CURRENT ASSETS, EXCLUDING LONG-TERM DEBT AND CAPITAL LEASES DUE
WITHIN ONE YEAR AND NOTES PAYABLE:
Notes receivable 209 (115)
Receivables (21,249) (4,290)6,889 11,333
Inventories (9,388) 9,972(6,676) (10,849)
Prepayments and other current assets (7,971) (8,176)(4,896) 831
Accounts payable 18,682 11,40311,060 (17,700)
Accrued interest 1,454 (2,251)4,331 1,371
Accrued and withheld taxes 16,637 14,8606,270 4,791
Other current liabilities (3,686) 1,683
--------- ---------
Total adjustments 130,320 182,499
--------- ---------
Net cash provided by operating activities 139,625 196,574
--------- ---------
Cash flows from investing activities:(11,558) (2,291)
------------ -----------------
TOTAL ADJUSTMENTS 41,639 31,692
------------ -----------------
NET CASH PROVIDED BY OPERATING ACTIVITIES 49,738 39,318
------------ -----------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (25,779) (49,942)(16,710) (8,085)
Net proceeds from bond, reserve and construction funds 1,143 21,616330 938
Decrease (increase) in investment in associated organizations 343 (28)138 231
Increase in other short-term investments (4,520) (4,306)(1,296) (1,293)
Increase in decommissioning fund (8,988) (7,709)
Net cash received in Corporate Restructuring -- 23,495
--------- ---------
Net cash used in investing activities (37,801) (16,874)
--------- ---------
Cash flows from financing activities:(4,467) (3,808)
------------ -----------------
NET CASH USED IN INVESTING ACTIVITIES (22,005) (12,017)
------------ -----------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Long-term debt proceeds, net (5,556) 100,404(2,597) (2,198)
Long-term debt payments (68,931) (302,617)
Premium paid on refinancing of debt (24,041) --(33,825) (30,820)
Increase in notes payable 3,982 --
Retirement of patronage capital -- (48,863)39,898 -
Increase in notes receivable under interim financing agreement (48,908) -
Other 1,412 (1,426)
--------- ---------
Net cash used in financing activities (93,134) (252,502)
--------- ---------
Net increase (decrease) in cash and temporary cash investments 8,690 (72,802)
Cash and temporary cash investments at beginning of period230 1,017
------------ -----------------
NET CASH USED IN FINANCING ACTIVITIES (45,202) (32,001)
------------ -----------------
NET DECREASE IN CASH AND TEMPORARY CASH INVESTMENTS (17,469) (4,700)
CASH AND TEMPORARY CASH INVESTMENTS AT BEGINNING OF PERIOD 106,235 63,215
132,783
--------- ---------
Cash and temporary cash investments at end of period------------ -----------------
CASH AND TEMPORARY CASH INVESTMENTS AT END OF PERIOD $ 71,90588,766 $ 59,981
--------- ---------
--------- ---------
Cash paid for:58,515
------------ -----------------
------------ -----------------
CASH PAID FOR:
Interest (net of amounts capitalized) $ 177,39652,415 $ 202,40058,026
Income taxes -- 830- -
The accompanying notes are an integral part of these condensed financial
statements.
6
Oglethorpe Power Corporation
Notes to Condensed Financial Statements
September 30,OGLETHORPE POWER CORPORATION
NOTES TO CONDENSED FINANCIAL STATEMENTS
MARCH 31, 1999 AND 1998 and 1997
(A) The condensed financial statements included herein have been prepared by
Oglethorpe Power Corporation (Oglethorpe), without audit, pursuant to
the rules and regulations of the Securities and Exchange Commission
(SEC). In the opinion of management, the information furnished herein
reflects all adjustments (which include only normal recurring
adjustments) and estimates necessary to present fairly, in all material
respects, the results for the periods ended September 30, 1998March 31, 1999 and 1997.1998.
Certain information and footnote disclosures normally included in
financial statements prepared in accordance with generally accepted
accounting principles have been condensed or omitted pursuant to such
SEC rules and regulations, although Oglethorpe believes that the
disclosures are adequate to make the information presented not
misleading. It is suggested that these condensed financial statements be
read in conjunction with the financial statements and the notes thereto
included in Oglethorpe's latest Annual Report on Form 10-K, as filed
with the SEC. Certain amounts for 19971998 have been reclassified to conform
with the current period presentation.
(B) In June 1998, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards (SFAS) No. 133, "Accounting for
Derivative Instruments and Hedging Activities." The standard requires
that all derivative instruments be recognized as assets or liabilities
and be measured at fair value. Oglethorpe is required to adopt SFAS No.
133 by January 1, 2000. Oglethorpe is currently assessing the impact
that adoption of SFAS No. 133 will have on results of operations and
financial condition and is undecided as to the date the standard will be
adopted.
(C) As discussed in Notes 1 and 2 of Notes to Financial Statements included
in Oglethorpe's Annual Report on Form 10-K for the fiscal year ended
December 31, 1997, Oglethorpe entered into long-term lease transactions
for its 74.6% undivided ownership interest in the Rocky Mountain Pumped
Storage Hydroelectric Project (Rocky Mountain).7
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
GENERAL
FUTURE POWER RESOURCES
Under the terms of these
transactions, Oglethorpe leased the facility to three institutional
investors for the useful life of the facility, who in turn leased it
back to Oglethorpe for a term of 30 years, through a wholly owned
subsidiary of Oglethorpe, Rocky Mountain Leasing Corporation. The assets
of Rocky Mountain Leasing Corporation are not available to pay creditors
of Oglethorpe or its affiliates.
7
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations
General
LEMWholesale Power Marketer Arrangements
As previously reported, Oglethorpe entered into long-term power marketer
arrangements effective January 1, 1997 for approximately 50% of the load
requirements of itsContracts, Oglethorpe's 39 retail electric
distribution cooperative members (the Members) may choose to supply all or a
portion of their future requirements with LG&E Energy Marketing Inc. (LEM), an indirect, wholly owned
subsidiarypurchases from suppliers other than
Oglethorpe. A new entity, Smarr EMC, was formed in 1998 by 36 of LG&E Power Inc.,the Members
to own a Delaware corporation (LPI),two-unit, 217 megawatt (MW) combustion turbine (CT) facility (CT
One). Commercial operation of this facility is scheduled for June 1999.
Construction and operation management services, as well as construction
financing, are currently being provided by Oglethorpe.
Smarr EMC, or similar entities, may also own future generation facilities on
behalf of LG&E Energy
Corp. (LG&E),Members who may decide to participate in such projects. One such
project is a four-unit, 492 MW CT facility (CT Two) currently under
consideration by the Members, which is a diversified energyscheduled for commercial operation by the
summer of 2000. Oglethorpe is providing construction management services company headquartered in
Louisville, Kentucky. In July 1998, LG&E announcedand
interim financing for this facility and anticipates that it was discontinuing its
merchant energy trading and sales business and associated gas gathering and
processing business and,will provide
operation management services as a result, recorded an after-tax loss on discontinued
operations of $225 million in the second quarter of 1998. LG&E stated that the
loss on discontinued operations results primarily from several fixed-price
energy marketing agreements, including the agreements between LEM and
Oglethorpe.
Oglethorpe has two agreements with LEM. One involves the load requirements of 37
of the 39 Members and has a term extending through 2011, with Oglethorpe and LEM
having the right to terminate the agreement beginning in 2002 and 2005,
respectively. The other agreement involves the load requirements of the otherwell.
In addition, two Members and has a term extending through 1999. Under the agreements, LEMhave formed an entity which is obligated to deliver, and Oglethorpe is obligated to take, approximately 50%constructing 90 MW of the load requirements of the participating Members. LEM has access to 50% of the
output of Oglethorpe's existing generating facilities and power purchase
arrangementsCT
capacity for its use.
At the request of LEM, the parties have discussed the future of these
arrangements. LEM also has initiated the contractually defined binding
arbitration process as to certain load projections providedcommercial operation by Oglethorpe to LEM
in connection with the execution of the larger of the two agreements. Oglethorpe
continues to receive power under the LEM agreements and believes the agreements
are enforceable against LEM and LG&E (with respect to the agreement relating to
the 37 Members) and LPI (with respect to the agreement relating to the other two
Members). Even so, given LG&E's announced intention to discontinue its merchant
energy trading and sales business, instead of performing itself, LEM could, with
consent of Oglethorpe and the Rural Utilities Service, make alternative
arrangements, including assigning performance to an acceptable third party, or
otherwise make Oglethorpe whole from any damages incurred as a result of
termination. Oglethorpe believes that LEM, LG&E and LPI have the ability,
financial and otherwise, to perform their obligations under these agreements.
The current uncertainty relating to the LEM arrangements does not adversely
affect Oglethorpe's ability to meet its Members' load requirements but could, in
the future, affect the sources and prices for such power. If LEM, LG&E and LPI
were to cease to perform their obligations under the LEM agreements or the LEM
agreements were to be terminated, Oglethorpe expects to be able to serve its
Members' needs through its existing owned and purchased capacity, supplemented
by additional capacity either purchased in the wholesale market, constructed or
otherwise acquired. Termination of
8
the LEM agreements would however eliminate a source of power at contractually
fixed prices and thus would introduce additional uncertainty regarding future
power costs and Member rates. Oglethorpe's management does not expect the
ultimate resolution of the LEM arrangements will have a material adverse effect
on its financial condition or results of operations.
Peaking Power Resources
As previously reported, Oglethorpe has forecasted the need for additional
capacity to meet the peaking requirements of its Members. Recently, Oglethorpe
has signed options to buy additional peaking power and has also arranged for the
construction of a 220-megawatt, natural gas-fired combustion turbine (Smarr CT)
to be located in Smarr, Georgia. The Smarr CT is being constructed by Siemens
Power Corporation and is expected to be operational for the summer of 1999.
The
Smarr CT willAll of these CTs are currently anticipated to be owned bydispatched in the Oglethorpe
pool of generation resources.
POWER PURCHASES FROM GPC
Oglethorpe has entered into an agreement with Georgia Power Company (GPC)
effective April 1, 1999 to purchase capacity and associated energy on a
new entity, Smarr EMC, which will be owned by 36take-or-pay basis. Under the agreement, Oglethorpe has committed to purchase 250
MW of the 39 Members of Oglethorpe. Oglethorpe expects to sign additional contracts
for peaking powercapacity and may also contract for or otherwise acquire additional
capacity.
Sale of EnerVision, Inc.
As discussed in Oglethorpe's Annual Report on Form 10-K for the fiscal year
ended December 31, 1997, in connection with the Corporate Restructuring,
Oglethorpe created a wholly owned subsidiary, EnerVision, Inc., Tailored Energy
Solutions (EnerVision), to which it transferred its marketing services business.
On October 15, 1998, the senior associates of EnerVision purchased the company
from Oglethorpe. EnerVision plans to continue to serve the Georgia electric
cooperatives and also plans to expand its services to clients nationwide. The
sale of EnerVision did not have a material effect on Oglethorpe's financial
condition or results of operations.
Results of Operations
For the Three Months and Nine Months Ended September 30, 1998 and 1997
As reported in its 1997 Annual Report on Form 10-K, Oglethorpe and the Members
completed a corporate restructuring (the Corporate Restructuring) on March 11,
1997, in which Oglethorpe was divided into three specialized operating
companies. Oglethorpe now operates the power supply business, Georgia
Transmission Corporation (GTC) operates the transmission business and Georgia
System Operations Corporation (GSOC) operates the system operations business.
The Condensed Statement of Revenues and Expenses and Comprehensive Margin for
the three months and nine months ended September 30, 1998 reflects Oglethorpe's
operations solely as a power supply company, whereas the Condensed Statement of
Revenues and Expenses and Comprehensive Margin for the nine months ended
September 30, 1997 reflects Oglethorpe's operations as a combined power supply,
transmission and system operations companyassociated energy through March 31, 1997,2006 and operations solely asan additional
250 MW for a power supply company thereafter. Although the Corporate
Restructuring was completed on March 11, 1997, pursuantone-year period beginning June 1, 1999. In addition to the restructuring
agreement amongthese
amounts, Oglethorpe GTC and GSOC, all transmission-related and systems
operations-related revenues were assignedmay elect, prior to Oglethorpe, and all
transmission-related and systems operations-related costs were paid or
reimbursed by Oglethorpe during the period March 11, 1997May 26, 1999, to purchase up to 250 MW
through March 31, 1997. Decreases
9
in depreciation2003. If Oglethorpe does not make the election, it will
purchase the additional 250 MW through August 31, 2000, will reduce this amount
to 125 MW from September 1, 2000 to August 31, 2001, and amortization, other operating expenses, operating margin,
net interest chargeswill not purchase any
additional amount after August 31, 2001. Upon the effectiveness of this
agreement, the Block Power Sale Agreement (BPSA) between Oglethorpe and net margin from 1997GPC was
terminated. The BPSA had provided for Oglethorpe to 1998 are primarily attributable
to the Corporate Restructuring.
See Oglethorpe's Annual Report on Form 10-K for the fiscal year endedpurchase 500 MW of capacity
and associated energy through December 31, 1997 for a pro forma presentation of2003. Unlike under the Statement of Revenues and Expenses
forBPSA,
Oglethorpe has no right (other than as described above) to reduce its purchase
obligations under the year ended Decembernew agreement prior to its expiration.
8
RESULTS OF OPERATIONS
FOR THE THREE MONTHS ENDED MARCH 31, 1997, reflecting the exclusion of the
transmission and system operations businesses, as though the Corporate
Restructuring had occurred at the beginning of 1997 (Note 11 of Notes to
Financial Statements).
Operating Revenues1999 AND 1998
OPERATING REVENUES
Revenues from sales to Members for the three months ended March 31, 1999 were
5.6% higher than the same period of 1998 and nine months ended
September 30, 1998megawatt-hour (MWh) sales to
Members were 18.1% and 12.1%11.8% higher for the current period. This resulted in a 5.5%
decrease in the average revenue per MWh from sales to Members for the current
period compared to the same periodsperiod of 1997.1998. The components of Member revenues
for the three months ended March 31, 1999 and 1998 were as follows:
Three Months
Ended March 31,
--------------------------
1999 1998
-------- ---------
(dollars in thousands)
Capacity revenues $155,213 $155,820
Energy revenues 89,830 76,123
-------- --------
Total $245,043 $231,943
-------- --------
-------- --------
While capacity revenues from Members for the ninethree months ended September
30,March 31, 1999
compared to 1998 were virtually unchanged, energy revenues were 18.0% higher for
the current quarter compared to the same period of 19971998. The higher MWh sales to
Members discussed above were reducedprimarily due to continued sales growth in the
removal of
capacity revenues relating to the transmission business, this effect was more
than offset by a significant increase in energy revenues from sales to Members.
Such energy revenues were 38.2% higher for the three months ended September 30,
1998 compared to the same period of 1997 and 44.3% higher for the nine-month
period compared to 1997. Megawatt-hour (MWh) sales toMembers' service territories. In addition, Oglethorpe provided the Members were 13.9% and
16.3% higher in the current three-month and nine-month periods comparedwith
additional energy to the
same periodsoffset lower delivery of 1997hydroelectric power from
Southeastern Power Administration (SEPA) due to prolonged hot weather during the summer months of
1998.lower than normal rainfall.
Oglethorpe's average energy revenue per MWh from sales to Members for the
three-month and nine-month periods were 21.4% and 24.1%period was 5.6% higher in 19981999 compared to 1997.1998. This increase
resulted primarily from higher purchased power energy costs as discussed below
under "Operating Expenses"."OPERATING EXPENSES."
Sales to non-Members were primarily from energy sales to other utilities and
power marketers, and, in 1997, pursuant to contractual arrangements with Georgia
Power Company (GPC).marketers. The following table summarizes the amounts of non-Member
revenues from these sources for the three months ended March 31, 1999 and nine months ended September
30, 1998 and 1997:1998:
Three Months
Nine Months
Ended September 30, Ended September 30,
------------------ ------------------March 31,
--------------------
1999 1998 1997 1998 1997
---- ----
---- ----
(dollars in thousands)
Sales to other utilities $ 9,212 $ 5,021 $22,626 $14,691$3,826 $2,225
Sales to power marketers 5,202 772 14,825 3,508
GPC-Power supply arrangements 0 283 0 12,847
ITS transmission agreements 0 0 0 2,180
------- ------- ------- -------1,895 1,099
------ ------
Total $14,414 $ 6,076 $37,451 $33,226
------- ------- ------- -------
------- ------- ------- -------$5,721 $3,324
------ ------
------ ------
Sales to other utilities represent sales made directly by Oglethorpe. Oglethorpe
sells for its own account any energy in excess ofavailable from the portion of its resources
dedicated to Morgan Stanley Capital Group Inc. (Morgan Stanley) that is not
scheduled by Morgan Stanley pursuant to its power marketer
9
arrangement. Sales to other utilities were higher for the three-month and nine-month periodsperiod of
1998
10
1999 compared to 1997 partly1998 primarily due to capacity revenues received under an
agreement entered into with Alabama Electric Cooperative to sell 100 MW of
capacity for the period June 1998 through December 2005 and partly due to higher energy
prices experienced in the wholesale electricity markets during the summer months
of 1998.2005.
Under the LEMLG&E Energy Marketing Inc. (LEM) and Morgan Stanley power marketer
arrangements, sales to the power marketers represented the net energy
transmitted on behalf of LEM and Morgan Stanley off-system on a daily basis from
Oglethorpe's total resources. Such energy was sold to LEM at Oglethorpe's cost,
subject to certain limitations, and to Morgan Stanley at Oglethorpe's cost, with certain
limited adjustments set forth in the arrangements.a contractually fixed
price. The volume of sales to power marketers depends primarily on the power
marketers' decisions for servicing their load requirements.
The revenues from power supply arrangements with GPC were derived in 1997 from
energy sales arising from dispatch situations whereby GPC caused Plant Wansley
to be operated when Oglethorpe's system did not require all of its contractual
entitlement to the generation. These revenues compensated Oglethorpe for its
costs because, under the operating agreement (before it was amended), Oglethorpe
was responsible for its share of fuel costs any time a unit operated. With the
commencement of the separate dispatch of Plant Wansley as of May 1, 1997, this
type of sale to GPC ended.
Another source of non-Member revenues in 1997 was payments received from GPC for
use of the Integrated Transmission System (ITS) and related transmission
interfaces. GPC compensated Oglethorpe to the extent that Oglethorpe's
percentage of investment in the ITS exceeded its percentage use of the system.
In such case, Oglethorpe was entitled to income as compensation for the use of
its investment by the other ITS participants. As a result of the Corporate
Restructuring, all of the revenues in this category have been GTC's revenues
since April 1, 1997.
Operating ExpensesOPERATING EXPENSES
Operating expenses were 26.2% and 19.2% higher infor the three months and nine
months ended September 30, 1998 compared to the same periods of 1997. For the
nine months ended September 30, 1998 depreciation and amortization and other
operating expensesMarch 31, 1999 were lower due to the elimination of these expenses relating
to the transmission business assumed by GTC in connection with the Corporate
Restructuring. However, the changes in fuel, production and purchased power
expenses did not result from the Corporate Restructuring.
Production expenses were 15.2%9.3% higher for the third quarter 1998
compared to the same period of 1997.1998. This increase was primarily resulted fromdue to 15.5%
higher operations and
maintenance costs at the various generation facilities.
Purchasedtotal purchased power costs for the three months and nine months ended September 30,
1998 were 61.2% and 56.9% highercurrent quarter compared to the
same periodsquarter of 1997.1998. Oglethorpe purchased 22.3% more MWhs in the three
months ended March 31, 1999 than in the same period of 1998. This resulted in
a decrease of 5.6% in the average cost per MWh of total purchased power. The
higher volume of purchased MWhs relates primarily to the portion of increased
Member load not contractually provided by the power marketers. Purchased
power costs are as follows:
Three Months
Ended March 31,
-------------------------
1999 1998
-------- --------
(dollars in thousands)
Capacity costs $25,408 $30,174
Energy costs 37,598 24,390
------- --------
Total $63,006 $54,564
------- --------
------- --------
Purchased power capacity costscost for the three months and nine months ended September 30,
1998 were 12.3% and 12.5%March 31, 1999 was
15.8% lower than the same periodsperiod of 1997.1998. These savings were primarily as a result
of the elimination, effective September 1, 1997,1998, of a 250-megawatt250 MW component block
under the Block Power Sale AgreementBPSA between Oglethorpe and GPC. Effective September 1, 1998, Oglethorpe
eliminated another 250-megawatt
11
component block. Purchased power energy costs for
the three-month and nine-month
periodsperiod of 19981999 were 103.4% and 121.4%54.2% higher compared to the same periodsperiod
of 1997 primarily1998 as a result of significant price increaseshigher volumes of purchased MWhs and higher prices
experienced in the wholesale electricity markets combined with higher volume of purchased MWhs. A
total of 27.2% and 44.1% more MWhs were purchasedmarkets. These factors resulted in three-month and nine-month
periods of 1998 compared toa
26.0% increase in the same periods of 1997 due to prolonged hot
weather during the summer months of 1998. The average cost of purchased power energy per MWh for the
three-month and nine-month periods were 59.9% and 53.7%
higher in 1998period compared to 1997. The higher volumes1998. This increase in the average cost of
purchased MWhs utilized
to serve Member load thatpower energy was not contractually provided by the power marketers
resulted in a significantprimarily responsible for an increase in the
average MWh cost of energy to the Members.
Other operating expenses for 1997 reflect expensesNET MARGIN AND COMPREHENSIVE MARGIN
Oglethorpe's net margin for the power delivery
portion of the business which was subsequently transferred to GTC in connection
with the Corporate Restructuring.
Other Income
Total other income for the ninethree months ended September 30, 1998 varied slightlyMarch 31, 1999 was $8.1
million compared to the same periods of 1997. For the nine months ended September 30,
1997, the caption "Other" reflected a margin of approximately $1.3$7.6 million related to Oglethorpe's marketing services business which was subsequently
transferred to EnerVision. As discussed in "General--Sale of EnerVision, Inc."
above, EnerVision was purchased from Oglethorpe by its senior associates on
October 15, 1998. For the nine months ended September 30, 1998, the caption
"Other" includes no net margin or loss from the results of operations and sale
of EnerVision.
Interest Charges
Net interest charges for the nine months ended September 30, 1998 decreased
compared to the same period of 1997 primarily due to the debt assumed by GTC in
connection with the Corporate Restructuring.
Net Margin and1998. Comprehensive
Margin
Oglethorpe'smargin for Oglethorpe is net margin (loss)adjusted for the three months and nine months ended
September 30, 1998 was $86,000 and $9.3 million, respectively, compared to
$(872,000) and $14.1 million for the same periods of 1997. Since Oglethorpe's
margin requirement is based on a ratio applied to interest charges, the
reduction in interest charges resulting from the Corporate Restructuring also
reduced Oglethorpe's margin requirement effective April 1, 1997. Such margin
earned by Oglethorpe from the transmission and system operations functions
during the first three months of 1997 was $2.3 million. The net loss for the
third quarter of 1997 was the result of a capacity charge adjustment in August
1997 to return $4 million of year-to-date margins in excess of the Indenture
requirements. The net margin achieved for the nine months ended September 30,
1998 is consistent with the 1998 margin requirement. The margin requirement for
1998 is approximately $1 million lower than budgeted due to lower interest
charges resulting from the refinancing of $430 million of Federal Financing Bank
(FFB) debt.
Comprehensive margin is now reported on the Condensed Statement of Revenues and
Expenses, consistent with Statement No. 130, "Reporting Comprehensive Income",
issued by the Financial
12
Accounting Standards Board. This Statement requires the reporting of all
components of changes in equity on the Statement of Revenues and Expenses. For
Oglethorpe, the only additional item being reported is the net change in unrealized
gains and losses on investments in available-for-sale securities.
Financial Condition10
FINANCIAL CONDITION
Total assets and total equity plus liabilities as of September 30, 1998March 31, 1999 were $4.5
billion, which was $25$20 million lessmore than the total at December 31, 19971998 due
primarily to an increase in notes and interim financing receivable for
construction of CT One and CT Two, offset by depreciation of electric plant. AssetsThese CT
projects are being financed on an interim basis by Oglethorpe through the
issuance of commercial paper. Oglethorpe expects to be reimbursed for the costs
relating to the construction of these projects at the time each facility becomes
commercially operable, which Oglethorpe anticipates will be June 1999 for CT One
and the summer of 2000 for CT Two. For a further discussion of these projects,
see "General--FUTURE POWER RESOURCES."
ASSETS
Property additions for the ninethree months ended September 30, 1998March 31, 1999 totaled $25.8$16.7
million primarily for purchases of nuclear fuel and for additions, replacements
and improvements to existing generation facilities.
The increasedecrease in cash is a result of cash provided from operations exceedingused in financing and investing
uses,activities, including property additions noted above and debt service activities of which $23.1 million in premiums were paid to the FFB in
conjunction with the refinancing of $430 million of debt.principal
repayments, exceeding cash provided from operations.
The increase in receivablesnotes and interim financing receivable resulted primarily from
significantly higher energy costs
billed to Members at September 30, 1998 compareduse of funds in the interim financing activities related to the CT units being
constructed. Included in notes and interim financing receivable balance fromas of March 31,
1999 is $54.4 million relating to the Members at December 31, 1997.
Inventories increased primarily as a resultconstruction of CT One and $38.9 million
relating to the coal inventories for Plants
Scherer and Wansley returning to more normal levels at September 30, 1998
compared to lower 1997 year-end levels caused by problems associated with rail
transportation.construction of CT Two.
Prepayments and other current assets increased primarily due to a $5.8 million
increase inthe estimated
payments to GPC for Plant Hatch operations and maintenance (O&M) costs for October 1998April
1999 compared to the estimate paid for January 1998.1999. The increase in O&M is related
to a planned refueling outagenuclear fuel purchases and costs to increase the actual and licensed thermal
output of Hatch Units No. 1 and No. 2. The increase in premiumother deferred charges is
related to 1999 refueling outages for Vogtle Unit No.1 and loss on reacquired debt resulted fromHatch Unit No.1. Such
costs will be amortized to expense over the above-mentioned refinancing premiums paid to FFB.
Equity and Liabilities18-month operating cycle of each
unit.
EQUITY AND LIABILITIES
Notes payable represent commercial paper issued by Oglethorpe as interim
financing for costs incurred in construction of the Smarr CT. Although
Oglethorpe is providing interim financing, the facility will be owned by Smarr
EMC.CT One and CT Two. Oglethorpe
will be reimbursed by Smarr EMCthe respective projects' owners for all construction costs
incurred prior to transfer of ownership, and accordingly, has recorded all
expenditures as a receivable from Smarr EMC. For further discussionreceivable. As of this
generation facility see "General--Peaking Power Resources" above.March 31, 1999, notes payable consisted of
$52.2 million relating to the financing of CT One and $38.7 million relating to
the financing of CT Two.
Accounts payable increased due primarily to the volumeHatch Unit No. 1 refueling
outage. This outage resulted in higher than normal charges for nuclear fuel and
O&M.
Accrued interest increased as a result of purchased power activity in
September 1998 compared to December 1997.
13the accrual for the July 1 interest
payment due for the Scherer Unit No. 2 lease obligation.
11
Accrued and withheld taxes increased as a result of the normal monthly accruals
offor property taxes, which are generally paid in the fourth quarter of the year.
MISCELLANEOUS
COMPETITION
The decreaseelectric utility industry in the United States is undergoing fundamental
change and is becoming increasingly competitive. This change is promoted by the
Energy Policy Act of 1992, recently adopted and proposed policies from the
Federal Energy Regulatory Commission (FERC) regarding mergers, transmission
access and pricing, federal and state deregulation initiatives, increased
consolidation and mergers of electric utilities, the proliferation of power
marketers and independent power producers, generation surpluses and deficits and
transmission constraints in certain regional markets and other factors.
Several states are in the process of implementing varying forms of "retail
wheeling" (the transmission of power for a third party directly to a retail
customer) and most others are in the various stages of considering retail
competition. Proposed federal legislation could mandate retail wheeling in
every state and otherwise deregulate the industry. No legislation related to
retail wheeling has yet been enacted in Georgia, and no bill is currently
pending in the Georgia legislature which would amend the Georgia Territorial
Electric Service Act (the Territorial Act) or otherwise affect the exclusive
right of the Members to supply power to their current service territories. In
1997, the staff of the Georgia Public Service Commission (GPSC) conducted a
series of workshops to solicit views from the various parties impacted by
electric industry restructuring and to discuss potential resolutions of these
issues, including "stranded costs" which would result from assets having
unrecovered costs in excess of their economically realizable value. The GPSC
issued a report identifying electric industry restructuring issues, potential
resolutions and the views of the parties who participated in the workshops.
The GPSC's order in the 1998 GPC rate case provides that there will be a
docket opened to address the mechanics of how stranded costs and stranded
benefits should be calculated, the estimated range of GPC's stranded costs
and benefits, the proper level of stranded cost recovery through rate
surcharges, and the proper disposition of any stranded benefits. The GPSC
does not have the authority under Georgia law to order retail wheeling or
amend the Territorial Act. Oglethorpe and the Members participated in the
GPSC staff workshops and are actively monitoring and studying the GPSC
proceedings and legislative initiatives in Congress and in other states to
take advantage of the experiences of cooperatives and other utilities in
other states to protect their interests in any future legislative activities
in Georgia.
Under current liabilities primarilyGeorgia law, the Members generally have the exclusive right to
provide retail electric service in their respective territories. Since 1973,
however, the Territorial Act has permitted limited competition among electric
utilities located in Georgia for sales of electricity to certain large
commercial or industrial customers. The owner of any new facility may receive
electric service from the power supplier of its choice if the facility is
located outside of municipal limits and has a connected demand upon initial full
operation of 900 kilowatts or more. The Members, with Oglethorpe's support, are
actively engaged in competition with other retail electric suppliers for these
new commercial and industrial loads. While the competition for 900-kilowatt
loads represents only limited competition in Georgia, this competition has given
Oglethorpe and the Members the opportunity to develop resources and strategies
to operate in an increasingly competitive market.
12
Oglethorpe cannot predict at this time the outcome of the various developments
that may lead to increased competition in the electric utility industry or the
effect of such developments on Oglethorpe or the Members. Nonetheless,
Oglethorpe has taken several steps to prepare for and adapt to the fundamental
changes that have occurred or are likely to occur in the electric utility
industry. In 1997, Oglethorpe completed the Corporate Restructuring and divided
itself into separate generation, transmission and system operations companies in
order to better serve its Members in a deregulated and competitive environment.
Since 1992, Oglethorpe also has pursued an interest cost reduction program,
which has included refinancings and prepayments of various debt issues, and that
has provided significant cost savings. Oglethorpe has also entered into
arrangements with power marketers to obtain the value that can be brought by
power marketers and to provide for future load requirements without taking all
the risk associated with traditional supply sources. (See Oglethorpe's 1998
Annual report on Form 10-K in "General--Corporate Restructuring", "Financial
Condition--Refinancing Transactions" and "Results of Operations--Power Marketer
Arrangements" in Item 7.)
Oglethorpe and the Members continue to consider and evaluate a wide array of
other potential actions to reduce costs and to enhance their competitiveness in
anticipation of future competition. Oglethorpe regularly considers industry
developments and trends to evaluate the challenges and opportunities they may
present for Oglethorpe. Among the alternatives subject to such consideration by
Oglethorpe are: additional power marketing arrangements or other alliance
arrangements; whether power supply requirements will continue to be met by the
current mix of ownership and purchase arrangements; whether power supply
resources will be owned by Oglethorpe or by separate entities; the effects of
proliferation of services offered by electric utilities; whether disposition of
assets or asset classes would enhance value; the effects of nuclear license
extensions; and other regulatory and business changes that may affect relative
values of generation classes or have impacts on the electric industry. These
activities on the part of Oglethorpe and the Members are in various stages of
study or preliminary consideration. Such studies and consideration necessarily
take account of and are subject to the legal, regulatory and contractual
(including financing and plant co-ownership arrangements) environment applicable
to Oglethorpe.
Many Members are now providing or considering proposals to provide
non-traditional products and services such as telecommunications and other
services. Depending on the nature of future competition in Georgia, there could
be reasons for the Members to separate their physical distribution business from
their energy business, or otherwise restructure their current businesses to
operate effectively under retail competition. Likewise, there could be reasons
for Oglethorpe to evaluate the disposition of generation assets, separating
different segments of its generation assets or business or other restructurings
of its business to operate more effectively under increasing competition.
Recent dispositions of fossil generation units throughout the country are being
evaluated by Oglethorpe, and the recent announcements relating to sales of
nuclear generation units and applications for nuclear license extensions are of
particular interest to Oglethorpe because of its substantial investment in
nuclear generation. These and other developments in the industry have resulted
from $2.3 million
improvement in negative book cash balances at September 30, 1998 comparedthe Rural Utilities Service (RUS) exploring the possibility of pursuing
nationwide measures for RUS and its borrowers that own nuclear generation
units. This exploration by RUS has included discussions with Oglethorpe and
others. Oglethorpe intends to 1997 year-end.
Miscellaneous
Yearpursue its discussions with RUS to determine if
13
there are feasible measures that Oglethorpe could take to enhance the value of
its assets or further its efforts to lower costs and increase its
competitiveness.
Oglethorpe's ongoing consideration of industry trends and developments may
present opportunities for Oglethorpe to enhance the value of its system or
otherwise to respond more effectively to increasing competition. However,
Oglethorpe cannot predict the results of its evaluation of these matters,
including discussions with RUS, or any action Oglethorpe might take based
thereon.
YEAR 2000
Issue
BackgroundBACKGROUND. The Year 2000 issue, which is common to most corporations, concerns
the ability of certain hardware, software, databases and databasesother devices that use
microprocessors to properly recognize date sensitive information related to the
Year 2000 and thereafter. Oglethorpe is heavily dependent upon complex computer
systems for all phases of power supply operations. Oglethorpe's operations
include both information technology (IT) systems, such as billing systems,
financial accounting systems, and human resource/payroll systems, as well as
non-IT systems that may have embedded microprocessors, such as those relating to
operations of the Rocky Mountain Pumped Storage Hydroelectric Facility (Rocky
Mountain), generation substations and Oglethorpe's headquarters facilities that
may have embedded microprocessors.facilities.
Management recognizes the seriousness of the Year 2000 issue and believes it has
dedicated adequate resources to address the issue. Oglethorpe's Senior Vice
President and Chief Financial Officer is in charge of its Year 2000 program, and
he reports directly to Oglethorpe's President and Chief Executive Officer. As
part of its business alliance with Oglethorpe, Intellisource Services
Solutions is providing
administration of Oglethorpe's Year 2000 program. Oglethorpe's Board of
Directors and its audit committee are monitoring this issue through periodic
updates from project management.
Project PhasesPROJECT PHASES. Oglethorpe has developed and is implementing a detailed strategy
to prevent any material disruption to operations.
Phase I began in April 1997 and included an inventory and assessment of
potential Year 2000 issues.problems in its systems. Substantially all IT and non-IT
systems were
assessed during this phase which concluded inhave been inventoried and assessed. Oglethorpe has completed an
inventory and assessment on its computer and embedded chip systems at Rocky
Mountain. Critical computer systems required to operate the fallRocky Mountain
control room have been upgraded. The computer system required to manage
maintenance activities and purchase materials for Rocky Mountain will be
upgraded by the third quarter of 1997.1999.
Phase II began in the fall of 1997 and includes remediation and testing of all
inventoried IT and non-IT systems. Remediation and testing efforts for all
inventoried internally developed systems applications are expected to be
completed by December 31, 1998. Externally purchased systems, including
financialhave been completed.
Oglethorpe is currently in the process of reassessing the completeness of the
original inventory. Financial accounting systems, procurement and materials
management systems and human resource/payroll systems are currently being evaluated for possible
upgrade or replacementexternally developed
and supported. None of these systems is Year 2000 ready. Oglethorpe is replacing
most of its financial accounting system modules and is retaining and upgrading
one module. Oglethorpe expects its financial accounting systems to be Year 2000
ready by the fourth quarter of 1999. Oglethorpe is replacing its procurement and
materials management systems and expects to complete this remediation in the
second quarter of 1999. Oglethorpe is upgrading its human resource/payroll
systems and expects to complete this remediation in the third quarter of 1999.
Remediation and testing efforts for systems at Rocky Mountain are
14
expected to be completed by March 31,the third quarter of 1999.
Phase III began recently and includes contingency planning, and an assessment of
Year 2000 readiness of material third parties including Oglethorpe's Members,
GTC, GSOC, GPC, power marketers and vendors.verification that all material
systems were properly inventoried, remediated and tested in Phases I and II.
This phase will be on-going throughout 19981999.
RELATIONSHIPS WITH THIRD PARTIES. Georgia Transmission Corporation (GTC) and
1999.
14
Relationships with Third Parties
GTC and GSOCGeorgia System Operations Corporation (GSOC) have also implemented a detailed
strategystrategies to ensure Year 2000 compliancereadiness of the systems utilized in their
transmission and systems control operations. The Year 2000 compliancereadiness plans
for Oglethorpe, GTC and GSOC were jointly developed and are being implemented
on the same schedule, as described above.
Oglethorpe is in the process of gatheringhas gathered information from the Members regarding their Year 2000
readiness. Based on this information, Oglethorpe will implement a follow-up
program to monitor the Members' Year 2000 compliancereadiness and will further assess any
impact on Oglethorpe's risks and contingency planning. During
1998, Georgia Electric Membership Corporation (the Members' trade association)
and Intellisource Services Solutions have conducted workshops forOglethorpe expects to
complete the information gathering process from the Members and have assisted some Members in their Year 2000 planning by providing
information for their use in this process.September 30,
1999.
All of Oglethorpe's co-owned generating plants, except Rocky Mountain, are
operated by GPC on behalf of itself as a co-owner and as agent for the other
co-owners. The Southern Company (Southern) is performing Year 2000 remediation and testing on all generation plants which are
operated by Southern's
subsidiary, GPC.GPC are being performed by GPC's parent company, Southern Company
(Southern). Southern estimates that total costs related to itsthis project on
behalf ofat the
GPC-operated plants will be approximately $38 million, of which approximately
$4.5 million is expected to be billed to Oglethorpe based on its ownership share
of these generation plants. To date, Oglethorpe has paid approximately $1.5$3.8
million for this project. Remaining costs will be expensed primarily in 1998 and 1999.
Southern reports that its Year 2000 program for the Georgia-based generating
plants is scheduled to be completed by June 1999. Southern is subject to the
informational requirements of the Securities Exchange Act of 1934, as amended,
and, in accordance therewith, files reports and other information with the
Securities and Exchange Commission.SEC.
During Phase III of its program, Oglethorpe plans to assess the Year 2000
readiness of other significant third parties, including power marketers (such as
LEM and Morgan Stanley), other utilities and vendors of materials and services.
Oglethorpe has identified over 400 such third parties, and is in the process of
prioritizing the parties from which Oglethorpe will require Year 2000
information. Oglethorpe expects to begin requesting information from these third
parties in the second quarter of 1999. This information will allow Oglethorpe to
perform contingency planning, including assessing the need to identify
alternative vendors. Project CostsOglethorpe may not be able to identify all third parties'
Year 2000 problems, and may not be able to develop adequate contingency plans if
third parties do not correct their Year 2000 problems.
PROJECT COSTS. In addition to the $4.5 million expected to be paid to GPC,
Oglethorpe currently estimates costs of approximately $665,000$370,000 to upgrade its
internal systems, including those relating to Rocky Mountain. To date,
Oglethorpe has spent approximately $350,000$270,000 of the estimated $665,000$370,000 on this
effort. In addition, Oglethorpe will likely replaceis upgrading or replacing its currentexternally
developed financial accounting, procurement and financialmaterials management, and human
resource/payroll systems
during 1999 to improve functionality and to avoid Year 2000
remediation efforts on those existing systems. Thesystems, at an estimated cost of replacing these two systems is
approximately $3.2 million.$4.0
million, of which $745,000 has been spent. Oglethorpe's policy is to expense as
incurred the maintenance and modification costs of existing software, including
those associated with
15
the Year 2000 project, and to capitalize and amortize over its useful life the
cost of new software. 15
Risk AssessmentOglethorpe also estimates that approximately $770,000 will
be incurred for Phase III, including costs associated with performing a
management evaluation of the Phase I and Phase II activities, and to perform the
contingency planning and the preparedness evaluation of key business
relationships. These costs are estimates, and actual costs could be higher.
Oglethorpe plans to pay for Year 2000 costs with general corporate funds. Year
2000 costs are being recovered from the Members through Oglethorpe's rates.
RISK ASSESSMENT. Oglethorpe has implemented a detailed process to minimize the
possibility of power supply interruptions related to Year 2000 challenges and
expects its IT and non-IT systems to be in complianceYear 2000 ready by December 31, 1999.
The most reasonably likely worst case scenario could involvewould be service interruptions to
Oglethorpe's Members andor the Members' retail consumers. These scenarios include
the loss of a generating unit or a source of purchased power, or a disruption in
transmission andor distribution services by GTC or the Members. Because Oglethorpe
is taking prudent steps to prepare for the Year 2000 challenges, it expects any
interruptions in power supply to be isolated and short in duration. However,
because of material relationships with third parties, it is too earlyOglethorpe may not be
able to fully assess the possibility of service interruptions to the ultimate
retail consumers.
There is also risk to the Members of billing and other business system failures
and of some reduction in net margin caused by interruptions in service and
reduced electrical demand by consumers because of their Year 2000 issues.
Oglethorpe has not fully assessed the impact of these risks on its financial
condition or results of operations.
Contingency PlanningActual results, costs, risks, or worst case scenarios related to Year 2000
issues may materially differ from those that Oglethorpe expects or estimates.
Factors that might cause material differences include, but are not limited to,
Oglethorpe's ability to locate and correct all microprocessors that are not Year
2000 ready, the readiness of third parties, and Oglethorpe's ability to develop
adequate contingency plans to respond to foreseen or unforeseen Year 2000
problems.
CONTINGENCY PLANNING. Oglethorpe recently began developing contingency plans for
its IT and non-IT systems. ThisTo assist Oglethorpe in this effort, the consulting
firm KPMG has been engaged to provide leadership and expertise to the Oglethorpe
staff developing the contingency planning processplans. The contingency plans will also focus on
non-compliance by material third parties withand assess the need to identify
alternative vendors and the need to increase inventory of materials and
supplies. The contingency plans are expected to be in place by June 30, 1999 and
will continue to be evaluated and tested throughout 1999. The goal of keepingthe
contingency planning process is to keep any service interruptions to a minimum
and of short duration.
Forward-Looking Statementsduration and Associated Risksto avoid disruptions in its billing or other
management processes. Oglethorpe may incur additional costs as a result of its
contingency plans.
FORWARD-LOOKING STATEMENTS AND ASSOCIATED RISKS
This Quarterly Report on Form 10-Q contains forward-looking statements,
including statements regarding, among other things,items, (i) anticipated trends in
Oglethorpe's business, (ii) Oglethorpe's future power supply resources and
arrangements and (iii) other management issues such as the Year 2000 issue.
These forward-looking statements are based largely on Oglethorpe's current
expectations and are subject to a number of risks and uncertainties, certain of
which are beyond Oglethorpe's control.
16
For certain factors that could cause actual results to differ materially from
those anticipated by these forward-looking statements, see Oglethorpe's 1997 Annual Report on Form 10-K in"COMPETITION" and
"YEAR 2000" herein and "CERTAIN FACTORS AFFECTING THE ELECTRIC UTILITY
INDUSTRY" in Item 1 and
"Competition" in Item 7.of Oglethorpe's 1998 Annual Report on Form 10-K. In light
of these risks and uncertainties, there can be no assurance that events
anticipated by the forward-looking statements contained in this Quarterly
Report will in fact transpire.
16ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Oglethorpe's market risks have not changed materially from the market
risks reported in the 1998 Form 10-K.
17
PART II - OTHER INFORMATION
ItemITEM 5. OTHER INFORMATION
Larry N. Chadwick, Sammy M. Jenkins, Ashley C. Brown and John S. Ranson,
whose initial terms as Directors expired in March 1999, were each elected for an
additional term of three years ending March 2002.
ITEM 6. Exhibits and Reports on FormEXHIBITS AND REPORTS ON FORM 8-K
(a) ExhibitsEXHIBITS
Number Description
------ ------------ --------- -------------
10.27 Long Term Transaction Service Agreement Under Southern Companies'
Federal Energy Regulatory Commission Electric Tariff Volume No. 4
Market-Based Rate Tariff, between Georgia Power Company and
Oglethorpe, dated as of February 26, 1999.
27.1 Financial Data Schedule (for SEC use only).
(b) Reports on FormREPORTS ON FORM 8-K
No reports on Form 8-K were filed by Oglethorpe for the quarter ended September
30, 1998.
17March 31,
1999.
18
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
Oglethorpe Power Corporation
(An Electric Membership Corporation)
Date: November 13, 1998May 14, 1999 By: /s/ Jack/S/ JACK L. King
-------------------------------------KING
----------------------------------------
Jack L. King
President and Chief Executive Officer
(Principal Executive Officer)
Date: November 13, 1998 /s/ MacMay 14, 1999 /S/ MAC F. Oglesby
-------------------------------------OGLESBY
----------------------------------------
Mac F. Oglesby
Treasurer
and Director
(Principal Financial Officer)
Date: November 13, 1998 /s/ ThomasMay 14, 1999 /S/ THOMAS A. Smith
--------------------------------------SMITH
----------------------------------------
Thomas A. Smith
Senior Vice President and Chief Financial Officer
(Chief(Principal Financial Officer)
Date: November 13, 1998 /s/ Robert D. Steele
--------------------------------------
Robert D. SteeleMay 14, 1999 /S/ WILLIE B. COLLINS
----------------------------------------
Willie B. Collins
Controller
(Chief Accounting Officer)
18
19