===============================================================================- --------------------------------------------------------------------------------
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
----------------------
FORM 10-Q
(MARK ONE)
[ X ]/X/ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED MARCH 31,JUNE 30, 1999
OR
[ ]/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM ___________ TO _____________
COMMISSION FILE NO. 33-7591
-----------------------
OGLETHORPE POWER CORPORATION
(AN ELECTRIC MEMBERSHIP CORPORATION)
(Exact name of registrant as specified in its charter)
GEORGIA 58-1211925
(State or other jurisdiction of (I.R.S. employer
incorporation or organization) identification no.)
POST OFFICE BOX 1349
2100 EAST EXCHANGE PLACE
TUCKER, GEORGIA 30085-1349
(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/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.
===============================================================================- --------------------------------------------------------------------------------
OGLETHORPE POWER CORPORATION
INDEX TO QUARTERLY REPORT ON FORM 10-Q
FOR THE QUARTER ENDED MARCH 31,JUNE 30, 1999
PAGE NO.
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
Condensed Balance Sheets as of March 31,June 30, 1999 (Unaudited)
and December 31, 1998 3
Condensed Statements of Revenues and Expenses and
Comprehensive Margin (Unaudited) for the Three Months
Ended March 31,and Six Months ended June 30, 1999 and 1998 5
Condensed Statements of Cash Flows (Unaudited)
for the ThreeSix Months Ended March 31,June 30, 1999 and 1998 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 1716
PART II - OTHER INFORMATION
Item 5. Other Information 18
Item 6. Exhibits and Reports on Form 8-K 1817
SIGNATURES 1918
2
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
OGLETHORPE POWER CORPORATION
CONDENSED BALANCE SHEETS
MARCH 31, 1999 AND DECEMBER 31, 1998
- --------------------------------------------------------------------------------------------------------OGLETHORPE POWER CORPORATION
CONDENSED BALANCE SHEETS
JUNE 30, 1999 AND DECEMBER 31, 1998
- --------------------------------------------------------------------------------
(dollars in thousands)
1999 1998
ASSETS (Unaudited)
-------------------------------------------------
-------------------------------------
ELECTRIC PLANT, AT ORIGINAL COST:
In service $4,856,328$4,861,487 $4,856,174
Less: Accumulated provision for depreciation (1,541,274)(1,571,082) (1,510,888)
------------------- ------------------
3,315,054-------------- --------------
3,290,405 3,345,286
Nuclear fuel, at amortized cost 86,91888,933 84,418
Construction work in progress 25,36522,983 20,948
------------------- ------------------
3,427,337-------------- --------------
3,402,321 3,450,652
------------------- -------------------------------- --------------
INVESTMENTS AND FUNDS:
Decommissioning fund, at market 122,287131,252 122,094
Deposit on Rocky Mountain transactions, at cost 56,69557,635 55,755
Bond, reserve and construction funds, at market 32,22932,160 32,909
Investment in associated organizations, at cost 16,093 16,231
Other, at cost 3,302 3,326
------------------- ------------------
230,606-------------- --------------
240,442 230,315
------------------- -------------------------------- --------------
CURRENT ASSETS:
Cash and temporary cash investments, at cost 88,76686,706 106,235
Other short-term investments, at market 74,22774,177 73,356
Customer receivables 104,030125,833 110,919
Notes and interim financing receivable 93,850115,171 45,151
Inventories, at average cost 83,45992,419 76,783
Prepayments and other current assets 26,29118,982 21,395
------------------- ------------------
470,623-------------- --------------
513,288 433,839
------------------- -------------------------------- --------------
DEFERRED CHARGES:
Premium and loss on reacquired debt, being amortized 208,766203,794 206,729
Deferred amortization of Scherer leasehold 99,807100,318 99,297
Discontinued projects, being amortized 34,15732,111 36,203
Deferred debt expense, being amortized 15,57315,333 15,825
Other 38,79539,615 33,405
------------------- ------------------
397,098-------------- --------------
391,171 391,459
------------------- ------------------
$4,525,664-------------- --------------
$4,547,222 $4,506,265
------------------- ------------------
------------------- -------------------------------- --------------
-------------- --------------
The accompanying notes are an integral part of these condensed financial
statements.
3
OGLETHORPE POWER CORPORATION
CONDENSED BALANCE SHEETS
MARCH 31, 1999 AND DECEMBER 31, 1998
- -------------------------------------------------------------------------------------------------------------------------------OGLETHORPE POWER CORPORATION
CONDENSED BALANCE SHEETS
JUNE 30, 1999 AND DECEMBER 31, 1998
- --------------------------------------------------------------------------------
(dollars in thousands)
1999 1998
EQUITY AND LIABILITIES (Unaudited)
----------------------------------------------------------------------------------
CAPITALIZATION:
CAPITALIZATION:
Patronage capital and membership fees (including unrealized
gainloss of $231$663 at March 31,June 30, 1999 and $1,006 at
December 31, 1998 on available-for-sale securities) $360,025$363,614 $352,701
Long-term debt 3,138,8213,118,375 3,177,883
Obligation under capital leases 280,530278,761 282,299
Obligation under Rocky Mountain transactions 56,69557,635 55,755
----------------- -----------------
3,836,071-------------- --------------
3,818,385 3,868,638
----------------- ------------------------------- --------------
CURRENT LIABILITIES:
Long-term debt and capital leases due within one year 102,921104,463 97,475
Accounts payable 57,73661,376 46,676
Notes payable 90,884109,342 50,986
Accrued interest 14,40515,609 10,074
Accrued and withheld taxes 6,48412,954 214
Other current liabilities 6,3438,271 17,901
----------------- -----------------
278,773-------------- --------------
312,015 223,326
----------------- ------------------------------- --------------
DEFERRED CREDITS AND OTHER LIABILITIES:
Gain on sale of plant, being amortized 57,66357,044 58,282
Net benefit of sale of income tax benefits, being amortized 24,02822,026 26,030
Net benefit of Rocky Mountain transactions, being amortized 88,39387,597 89,189
Accumulated deferred income taxes 63,203 63,203
Decommissioning reserve 155,795164,522 156,021
Other 21,73822,430 21,576
----------------- -----------------
410,820-------------- --------------
416,822 414,301
----------------- -----------------
$4,525,664-------------- --------------
$4,547,222 $4,506,265
----------------- -----------------
----------------- ------------------------------- --------------
-------------- --------------
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 MONTHS ENDED MARCH 31, 1999 AND 1998
- ------------------------------------------------------------------------------------------------------------------OGLETHORPE POWER CORPORATION
CONDENSED STATEMENTS OF REVENUES AND EXPENSES AND COMPREHENSIVE MARGIN
(UNAUDITED)
FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 1999 AND 1998
- --------------------------------------------------------------------------------
(dollars in thousands)
Three Months Ended June 30, Six Months Ended June 30,
1999 1998 ------------------------------------------------------1999 1998
------------------------- -------------------------
OPERATING REVENUES:
OPERATING REVENUES:
Sales to Members $245,043 $231,943$262,540 $297,014 $507,583 $528,957
Sales to non-Members 5,721 3,324
--------------- ---------------11,377 19,713 17,099 23,037
----------- ----------- ----------- -----------
TOTAL OPERATING REVENUES 250,764 235,267
--------------- ---------------273,917 316,727 524,682 551,994
----------- ----------- ----------- -----------
OPERATING EXPENSES:
Fuel 41,535 39,86746,606 48,978 88,141 88,845
Production 50,311 46,93252,559 48,486 102,847 95,417
Purchased power 63,006 54,56482,729 130,141 145,735 184,705
Depreciation and amortization 33,619 31,123
--------------- ---------------33,681 31,077 67,300 62,199
----------- ----------- ----------- -----------
TOTAL OPERATING EXPENSES 188,471 172,486
--------------- ---------------215,575 258,682 404,023 431,166
----------- ----------- ----------- -----------
OPERATING MARGIN 62,293 62,781
--------------- ---------------58,342 58,045 120,659 120,828
----------- ----------- ----------- -----------
OTHER INCOME (EXPENSE):
InterestInvestment income 7,455 7,84010,610 8,273 18,064 16,113
Amortization of net benefit of sale of income tax benefits 2,799 2,7982,799 5,597 5,596
Allowance for equity funds used during construction 27 2219 9 46 31
Other 810 125
--------------- ---------------1,017 788 1,804 913
----------- ----------- ----------- -----------
TOTAL OTHER INCOME 11,091 10,785
--------------- ---------------14,445 11,869 25,511 22,653
----------- ----------- ----------- -----------
INTEREST CHARGES:
Interest on long-term debt and other obligations 65,745 66,14568,242 68,397 133,987 134,541
Allowance for debt funds used during construction (460) (205)
--------------- ---------------62 (73) (398) (278)
----------- ----------- ----------- -----------
NET INTEREST CHARGES 65,285 65,940
--------------- ---------------68,304 68,324 133,589 134,263
----------- ----------- ----------- -----------
NET MARGIN 8,099 7,6264,483 1,590 12,581 9,218
Net change in unrealized (loss) gain on available-for saleavailable-for-sale securities (775) 229
--------------- ---------------(894) 367 (1,668) 596
----------- ----------- ----------- -----------
COMPREHENSIVE MARGIN $7,324 $7,855
--------------- ---------------
--------------- ---------------$3,589 $1,957 $10,913 $9,814
----------- ----------- ----------- -----------
----------- ----------- ----------- -----------
The accompanying notes are an integral part of these condensed financial
statements.
5
OGLETHORPE POWER CORPORATION
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
FOR THE THREE MONTHS ENDED MARCH 31, 1999 AND 1998
- -------------------------------------------------------------------------------------------------------------------------------OGLETHORPE POWER CORPORATION
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
FOR THE SIX MONTHS ENDED JUNE 30, 1999 AND 1998
- --------------------------------------------------------------------------------
(dollars in thousands)
1999 1998
-----------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net margin $ 8,09912,581 $ 7,626
------------ -----------------9,218
-------------- --------------
ADJUSTMENTS TO RECONCILE NET MARGIN TO NET CASH
PROVIDED BY OPERATING ACTIVITIES:
Depreciation and amortization 36,186 43,55484,167 85,413
Allowance for equity funds used during construction (27) (22)(46) (31)
Amortization of deferred gains (619) (619)(1,237) (1,237)
Amortization of net benefit of sale of income tax benefits (2,799) (2,798)(5,597) (5,596)
Other 3,269 4,2068,624 8,501
CHANGE IN NET CURRENT ASSETS, EXCLUDING LONG-TERM DEBT
AND CAPITAL LEASES DUE WITHIN ONE YEAR AND NOTES PAYABLE:
Customer receivables (14,914) (76,872)
Notes receivable 209 (115)
Receivables 6,889 11,333415 (293)
Inventories (6,676) (10,849)(15,636) (9,009)
Prepayments and other current assets (4,896) 8312,413 (2,195)
Accounts payable 11,060 (17,700)14,700 73,780
Accrued interest 4,331 1,3715,535 (3,176)
Accrued and withheld taxes 6,270 4,79112,740 10,682
Other current liabilities (11,558) (2,291)
------------ -----------------(9,630) (4,493)
-------------- --------------
TOTAL ADJUSTMENTS 41,639 31,692
------------ -----------------81,534 75,474
-------------- --------------
NET CASH PROVIDED BY OPERATING ACTIVITIES 49,738 39,318
------------ -----------------94,115 84,692
-------------- --------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (16,710) (8,085)(32,454) (15,786)
Net proceeds from bond, reserve and construction funds 330 93892 572
Decrease in investment in associated organizations 138 231272
Increase in other short-term investments (1,296) (1,293)(1,832) (3,015)
Increase in decommissioning fund (4,467) (3,808)
------------ -----------------(10,868) (7,631)
-------------- --------------
NET CASH USED IN INVESTING ACTIVITIES (22,005) (12,017)
------------ -----------------(44,924) (25,588)
-------------- --------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Long-term debt proceeds, net (2,597) (2,198)(4,667) (24,133)
Long-term debt payments (33,825) (30,820)(52,938) (51,224)
Increase in notes payable 39,89858,356 -
Increase in notes receivable under interim financing agreement (48,908)(70,435) -
Other 230 1,017
------------ -----------------964 1,236
-------------- --------------
NET CASH USED IN FINANCING ACTIVITIES (45,202) (32,001)
------------ -----------------(68,720) (74,121)
-------------- --------------
NET DECREASE IN CASH AND TEMPORARY CASH INVESTMENTS (17,469) (4,700)(19,529) (15,017)
CASH AND TEMPORARY CASH INVESTMENTS AT BEGINNING OF PERIOD 106,235 63,215
------------ ------------------------------- --------------
CASH AND TEMPORARY CASH INVESTMENTS AT END OF PERIOD $ 88,76686,706 $ 58,515
------------ -----------------
------------ -----------------48,198
-------------- --------------
-------------- --------------
CASH PAID FOR:
Interest (net of amounts capitalized) $ 52,415108,936 $ 58,026123,020
Income taxes - -
The accompanying notes are an integral part of these condensed financial
statements.
6
OGLETHORPE POWER CORPORATION
NOTES TO CONDENSED FINANCIAL STATEMENTS
MARCH 31,JUNE 30, 1999 AND 1998
(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 March 31,June 30, 1999 and 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 1998 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, 2000.2001. 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.condition.
7
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
GENERAL
FUTUREPOWER PURCHASES FROM GPC
Oglethorpe entered into an agreement with Georgia Power Company (GPC) effective
April 1, 1999 to purchase capacity and associated energy on a take-or-pay basis.
In connection with this agreement, the Block Power Sale Agreement (BPSA)
between Oglethorpe and GPC was terminated. Under the new agreement,
Oglethorpe will purchase capacity and associated energy as follows: 750
megawatt (MW) through May 31, 2000, 500 MW from June 1, 2000 to August 31,
2000, 375 MW from September 1, 2000 to August 31, 2001, and 250 MW from
September 1, 2001 to March 31, 2006.
DOYLE POWER PURCHASE
Oglethorpe has entered into an agreement with Doyle I, LLC, a limited liability
company to be owned by an affiliate of Enron Capital & Trade Resources Corp. and
one member of Oglethorpe, to purchase approximately 325 MW of peaking capacity
over a 15-year term. Delivery is anticipated to commence by June 1, 2000,
subject to the generating units underlying the purchase being ready for
commercial operation.
MEMBER POWER RESOURCES
Under the Wholesale Power Contracts, Oglethorpe's 39 retail electric
distribution cooperative members (the Members) may choose to supply all or a
portion of their future requirements with purchases from suppliers other than
Oglethorpe. A new entity, Smarr EMC, was formed in 1998 by 36 of the Members to
own a two-unit, 217 megawatt (MW)MW combustion turbine (CT) facility, (CT
One)Smarr Energy Facility
(Smarr CT). CommercialSmarr CT was declared in commercial operation of this facility is scheduled forin June 1999.
Construction andOglethorpe is providing operation management services as well as construction
financing, are currently being provided by Oglethorpe.for this facility.
Smarr EMC, or similar entities, may also own future generation facilities on
behalf of Members who may decide to participate in such projects. OneSewell Creek
Energy Facility (Sewell Creek CT) is one such project currently under
construction in which 31 Members are participating. Sewell Creek CT is a
four-unit, 492 MW CT facility (CT Two) currently under
consideration by the Members, which is scheduled for commercial operation by the summer
of 2000. Oglethorpe is providing construction management services and interim
financing for this facility and anticipates that it will provide operation
management services as well.
In addition, two Members have formed an entity which is constructingthat constructed 90 MW of CT capacity,
forwhich began commercial operation byin the summer of 1999.
All of these CTs are currently anticipated to be dispatched 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
take-or-pay basis. Under the agreement, Oglethorpe has committed to purchase 250resources, except for 50 MW of capacity and associated energy through March 31, 2006 and an additional
250the 90 MW for a one-year period beginning June 1, 1999. In addition to these
amounts, Oglethorpe may elect, prior to May 26, 1999, to purchase up to 250 MW
through March 31, 2003. 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 will not purchase any
additional amount after August 31, 2001. Upon the effectiveness of this
agreement, the Block Power Sale Agreement (BPSA) between Oglethorpe and GPC was
terminated. The BPSA had provided for Oglethorpe to purchase 500 MW of capacity
and associated energy through December 31, 2003. Unlike under the BPSA,
Oglethorpe has no right (other than as described above) to reduce its purchase
obligations under the new agreement prior to its expiration.owned by two
Members.
8
RESULTS OF OPERATIONS
FOR THE THREE MONTHS AND SIX MONTHS ENDED MARCH 31,JUNE 30, 1999 AND 1998
OPERATING REVENUES
Revenues from sales to Members for the three months and six months ended March 31,June
30, 1999 were 5.6% higher11.6% and 4.0% lower than the same periodperiods of 1998 and megawatt-hour1998. Megawatt-hour
(MWh) sales to Members were 11.8%1.5% and 6.2% higher forin the current period. This resulted in a 5.5%
decrease inthree-month and
six-month periods compared to the same periods of 1998. The average revenue per
MWh from sales to Members was 12.9% and 9.6% less for the current periodperiods
compared to the same periodperiods of 1998. The components of Member revenues for the
three months and six months ended March 31,June 30, 1999 and 1998 were as follows:
Three Months Six Months
Ended March 31,
--------------------------June 30, Ended June 30,
-------------- --------------
1999 1998 -------- ---------1999 1998
---- ---- ---- ----
(dollars in thousands)
Capacity revenues $155,213 $155,820$155,210 $155,862 $310,424 $311,683
Energy revenues 89,830 76,123107,330 141,152 197,159 217,274
-------- -------- -------- --------
Total $245,043 $231,943$262,540 $297,014 $507,583 $528,957
-------- -------- -------- --------
-------- -------- -------- --------
While capacity revenues from Members for the three months and six months ended
March 31,June 30, 1999 compared to 1998 were virtually unchanged, energy revenues were
18.0% higher24.0% and 9.3% lower for the current periods compared to the same periods of
1998. The decrease in energy revenues in 1999 was due to the pass-through in
1998 of significant price increases for purchased power in the wholesale
electricity markets (see "OPERATING EXPENSES" below). Oglethorpe's average
energy revenue per MWh from sales to Members for the three-month and six-month
periods were 25.1% and 14.5% lower in 1999 compared to 1998. As noted above, MWh
sales to Members increased during the current quarter compared to the same period of 1998. The higher MWh sales to
Members discussed above were primarily1998 due to
continued sales growth in the Members' service territories. In addition,
Oglethorpe provided the Members with additional energy to offset lower delivery
of hydroelectric power from Southeastern Power Administration (SEPA) due to lower
than normal rainfall.
Oglethorpe's average energy revenue per MWh from sales to Members for the
three-month period was 5.6% higher in 1999 compared to 1998. This increase
resulted primarily from higher purchased power energy costs as discussed below
under "OPERATING EXPENSES."
Sales to non-Members were primarily from energy sales to other utilities and
power marketers. The following table summarizes the amounts of non-Member
revenues from these sources for the three months and six months ended March 31,June 30,
1999 and 1998:
9
Three Months Six Months
Ended March 31,
--------------------June 30, Ended June 30,
-------------- --------------
1999 1998 1999 1998
---- ---- ---- ----
(dollars in thousands)
Sales to other utilities $3,826 $2,225$ 8,878 $11,189 $12,705 $13,414
Sales to power marketers 1,895 1,099
------ ------2,499 8,524 4,394 9,623
-------- -------- -------- --------
Total $5,721 $3,324
------ ------
------ ------$11,377 $19,713 $17,099 $23,037
-------- -------- -------- --------
-------- -------- -------- --------
Sales to other utilities represent sales made directly by Oglethorpe. Oglethorpe
sells for its own account any energy available 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 period of
1999 compared to 1998 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.
Under the LG&E Energy Marketing Inc. (LEM) and Morgan Stanley power marketer
arrangements, sales to the power marketers representedrepresent 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 a contractually fixed
price. The volume of sales to power marketers depends primarily on the power
marketers' decisions for servicing their load requirements.
OPERATING EXPENSES
Operating expenses for the three months and six months ended March 31,June 30, 1999 were
9.3% higher16.7% and 6.3% lower compared to the same periods of 1998. This decrease was
primarily due to the 36.4% and 21.1% decline in total purchased power costs for
the current three-month and six-month periods compared to the same periods of
1998. Oglethorpe purchased 28.1% and 11.1% less MWhs in the three months and six
months ended June 30, 1999 than in the same periods of 1998. The average cost
per MWh of total purchased power was 11.6% and 11.2% less in 1999 compared to
the comparable periods of 1998. The lower volume of purchased MWhs was due to
milder weather in the current quarter compared to the same period of 1998. This increase was primarily due to 15.5%
higher total purchased power costs for the current quarter compared to the
same quarter of 1998. Oglethorpe purchased 22.3% more MWhs in the three
months ended March 31, 1999 than in the same period of 1998. ThisThe
milder weather also resulted in a decrease of 5.6% in the average cost per MWh of total purchased power. The
higher volume of purchased MWhs relates primarilylower sales to the portion of increased
Member load not contractually provided by theother utilities and power
marketers. Purchased power costs arewere as follows:
Three Months Six Months
Ended March 31,
-------------------------June 30, Ended June 30,
-------------- --------------
1999 1998 -------- --------1999 1998
---- ---- ---- ----
(dollars in thousands)
Capacity costs $25,408 $30,174$26,941 $32,055 $52,349 $62,229
Energy costs 37,598 24,390
-------cost 55,788 98,086 93,386 122,476
-------- -------- -------- --------
Total $63,006 $54,564
-------$82,729 $130,141 $145,735 $184,705
-------- --------------- -------- --------
-------- -------- -------- --------
Purchased power capacity cost for the three months and six months ended March 31,June 30,
1999 was 15.8%approximately 16.0% and 15.9% lower than the same periodcomparable periods of
1998. These savings were primarily a result of the elimination, effective
September 1, 1998, of a 250 MW component block
10
under the BPSA between Oglethorpe and GPC. Purchased power energy costs for
the three-month periodand six-month periods of 1999 were 54.2% higher43.1% and 23.8% lower
compared to the same periodperiods of 1998 as a result of higher volumes of
purchased MWhs and higher prices experienced in the wholesale electricity
markets.markets during the second quarter of 1998 compared to the current quarter.
These factors resulted in a 26.0% increase20.9% and 14.2% decrease in the average cost of
purchased power energy per MWh for the three-month periodand six-month periods of
1999 compared to 1998. This increasedecrease in the average cost of purchased power
energy was primarily responsible for an increasethe decrease in the average MWh cost of
energy to the Members.
OTHER INCOME
Investment income was higher in the current quarter compared to the same period
of 1998 partly due to higher earnings from the decommissioning fund and partly
due to interest earnings on the notes and interim financing receivable for Smarr
CT and Sewell Creek CT. See "General--MEMBER POWER RESOURCES" for a further
discussion of these projects.
NET MARGIN AND COMPREHENSIVE MARGIN
Oglethorpe's net margin for the three months and six months ended March 31,June 30, 1999
was $8.1$4.5 million and $12.6 million, respectively, compared to $7.6$1.6 million and
$9.2 million for the same periodperiods of 1998. The higher net margin resulted
primarily from lower than budgeted fixed operations and maintenance (O&M)
expenses and from lower than budgeted interest rates on the variable portion of
long-term debt. Comprehensive margin for Oglethorpe is net margin adjusted for
the net change in unrealized gains and losses on investments in
available-for-sale securities.
10
FINANCIAL CONDITION
Total assets and total equity plus liabilities as of March 31,June 30, 1999 were $4.5
billion, which was $20$41.0 million more than the total at December 31, 1998 due
primarily to an increase in the notes and interim financing receivable for
construction of Smarr CT One and Sewell Creek CT, Two, offset by depreciation of plant.
These CT projects are being financed on an interim basis by Oglethorpe through the
issuance of commercial paper. On July 8, 1999, Oglethorpe expectswas reimbursed $56.3
million for Smarr CT project costs funded by Oglethorpe through May 31, 1999.
Oglethorpe used these funds to be reimbursed for the costs
relatingretire $53.2 million in outstanding commercial
paper that was issued to fund the construction of these projects at the time each facility becomes
commercially operable, which Oglethorpe anticipates will be June 1999Smarr CT. See "General--MEMBER
POWER RESOURCES" for CT One
and the summer of 2000 for CT Two. For a further discussion of these projects,
see "General--FUTURE POWER RESOURCES."projects.
ASSETS
Property additions for the threesix months ended March 31,June 30, 1999 totaled $16.7$32.5 million
primarily for purchases of nuclear fuel and for additions, replacements and
improvements to existing generation facilities.
The decrease in cash is a result of cash used in financing and investing
activities, including property additions noted above and debt principal
repayments, exceeding cash provided from operations.
The increase in receivables resulted from significantly higher energy costs
billed to Members at June 30, 1999 compared to the receivable balance from the
Members at December 31, 1998.
11
The increase in notes and interim financing receivable resulted primarily
from use of funds in the interim financing activities related to the
construction of Smarr CT units being
constructed.and Sewell Creek CT. Included in notes and interim
financing receivable as of March 31,June 30, 1999 is $54.4$57.2 million relating to the
construction of Smarr CT One and $38.9$57.5 million relating to the construction of
Sewell Creek CT. As noted above, the note related to Smarr CT Two.was repaid in
July 1999.
Inventories of fossil fuel were greater at June 30, 1999 than at December 31,
1998 as a result of normal seasonal increases in anticipation of higher
demand for electricity during the summer season. In addition, inventories
were greater because Oglethorpe's fossil fuel plants have been utilized less
than projected due to decisions made by LEM and Morgan Stanley under the
power marketer arrangements.
Prepayments and other current assets increaseddecreased primarily due to the estimated
payments to GPC for Plant Hatch operations and maintenance (O&M)O&M costs for AprilJuly 1999 compared to the
estimate for January 1999. The increase in O&M is related
to nuclear fuel purchases and costs to increase the actual and licensed thermal
output of Hatch Units No. 1 and No. 2.
The increase in other deferred charges is related to 1999 refueling outages
for Vogtle Unit No.1 and Hatch Unit No.1. Such costs will be amortized to
expense over the 18-month operating cycle of each unit.
EQUITY AND LIABILITIES
Notes payable represent commercial paper issued by Oglethorpe as interim
financing for costs incurred in the construction of Smarr CT One and Sewell Creek
CT. In July 1999, Oglethorpe was reimbursed $56.3 million for Smarr CT
Two.project costs funded by Oglethorpe willthrough May 31, 1999. Oglethorpe used
these funds to retire $53.2 million in outstanding commercial paper which was
issued to fund the construction of Smarr CT. Oglethorpe expects to be
reimbursed by the respective projects' owners for all construction costs
incurred prior to transfer of ownership, and accordingly, has recorded all
expenditures as a receivable. As of March 31, 1999, notes payable consisted of
$52.2 million relating to the financingconstruction of Sewell Creek CT One and $38.7 million relating toshortly
after it is placed into commercial operation, which Oglethorpe anticipates
will be by the financingsummer of CT Two.2000.
Accounts payable increased due primarily to the Hatch Unit No. 1 refueling
outage. This outage resultedvolume of purchased power activity in
higher than normal charges for nuclear fuel and
O&M.June 1999 compared to December 1998.
Accrued interest increased as a result of the 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 for property taxes, which are generally paid in the fourth quarter
of the year.
The decrease in other current liabilities primarily resulted from $8.2
million improvement in negative book cash balances at June 30, 1999 compared
to 1998 year-end.
12
MISCELLANEOUS
COMPETITION
The electric 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 Georgia 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 increasedFor information about competition in the electric utility industry orand the
effect of such developments on Oglethorpe or the Members. Nonetheless,
Oglethorpe has taken several steps to prepare foractions 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.)potential actions Oglethorpe and the Members continue to considerhave taken and evaluate a wide array of
other potential actionsare
considering and evaluating 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 impactsincreased competition, see Oglethorpe's Quarterly
Report 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 reasonsForm 10-Q 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
in the 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 pursue 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.quarterly period ended March 31, 1999.
YEAR 2000
BACKGROUND. The Year 2000 issue, which is common to most corporations,
concerns the ability of certain hardware, software, databases and other
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.
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 is providingassisting in the 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 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 problems in its systems. Substantially all IT and
non-IT systems have beenwere inventoried and assessed.
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 complete.
Financial accounting systems, procurement and materials management systems
and human resource/payroll systems are externally developed and supported.
Currently, only the financial accounting systems are not Year 2000 ready.
Oglethorpe has completed an
inventoryis replacing most of its financial accounting system modules and
assessment onis retaining and upgrading one module. Oglethorpe expects its computer and embedded chipfinancial
accounting systems at Rocky
Mountain.to be Year 2000 ready by the fourth quarter of 1999. The
financial accounting systems project is approximately 60% complete. Critical
computer systems required to operate the Rocky 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 1999.
Phase IIIII began in the fallspring of 1997 and includes remediation and testing1999 with a verification of all
inventoried IT and non-IT systems. Remediation and testing efforts for all
inventoried internally developed systems applications have 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 externally 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
1413
expected to be completed by the third quarter of 1999.inventory. Phase III began recently andalso includes contingency planning, an assessment of
Year 2000 readiness of material third parties and verification that all
material systems wereare being properly inventoried, remediated and tested in Phases I and II.tested. This phase will be
on-going throughout 1999.
RELATIONSHIPS WITH THIRD PARTIES. Georgia Transmission Corporation (GTC) and
Georgia System Operations Corporation (GSOC) have implemented detailed
strategies to ensure Year 2000 readiness of the systems utilized in their
transmission and systems control operations. The Year 2000 readiness plans for
Oglethorpe, GTC and GSOC were jointly developed and are being implemented on the
same schedule, as described above.
Oglethorpe has gathered information from the Members regarding their Year
2000 readiness. Based on this information, Oglethorpe will implementis conducting a
follow-up program to monitor the Members' Year 2000 readiness and will
further assess any impact on Oglethorpe's risks and contingency planning.
Oglethorpe expects to complete the information gathering process from the
Members by 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. Year 2000 remediation and testing on all generation plants which are
operated by GPC are being performed by GPC's parent company, The Southern
Company (Southern). SouthernOglethorpe estimates that total costs related to this project at the
GPC-operated plantsapproximately $4.3 million will be
approximately $38 million, of which approximately
$4.5 million is expected to be billed to Oglethorpeby Southern based on its ownership share of thesethe co-owned generation
plants. To date, Oglethorpeplants, of which approximately $4.0 million has paid approximately $3.8
million for this project.been paid. Remaining costs will
be expensed primarily in 1999. Southern reports that its Year 2000 program for
the Georgia-based generating plants is scheduledwas completed on schedule in June 1999.
Southern also reports that its Year 2000 program will continue to be completed by June 1999.monitor the
affected computer systems, devices and applications into the Year 2000. 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 SEC.
During Phase III of its program, Oglethorpe plans to assessis in the process of assessing 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 4001,200 such third parties, and is in the process of prioritizing the parties from which approximately
60 are deemed to be material. Oglethorpe will require Year 2000
information. Oglethorpe expects to begin requestinghas requested information from these
third parties in the second quarter ofand expects to complete this process by September 30, 1999. This
information will allow Oglethorpe to perform contingency planning, including
assessing the need to identify alternative vendors. Oglethorpe 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$4.3 million expected to be paid to GPC,Southern,
Oglethorpe currently estimates project costs of approximately $370,000$5.1 million.
These costs are being incurred to upgrade its internal systems, including those
relating to Rocky Mountain. To date,
Oglethorpe has spent approximately $270,000 of the estimated $370,000 on this
effort. In addition, Oglethorpe is upgradingMountain, and to upgrade or replacingreplace its externally developed
financial accounting, procurement and materials management and human
resource/payroll systemssystems. These costs
are also being incurred to improve functionality and to avoid Year 2000
remediation efforts on those systems, at an estimated cost of approximately $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. Oglethorpe also estimates that approximately $770,000 will
be incurred for Phase III, including costs associated with performingperform 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. Oglethorpe's policy is to
expense as incurred the maintenance and modification costs of existing software,
including those associated with the Year 2000 project, and to capitalize and
amortize over
14
its useful life the cost of new software. To date, Oglethorpe has spent
approximately $1.8 million of the $5.1 million on these efforts. 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 Year 2000 ready by December 31, 1999.
The most reasonably likely worst case scenario would be service interruptions to
Oglethorpe's Members or the Members' retail consumers. These scenarios include
the loss of a generating unit or a source of purchased power, or a disruption in
transmission or 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, Oglethorpe 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.
Actual 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 developinghas developed contingency plans for its IT and
non-IT systems. To assist Oglethorpe in this effort,systems with the assistance of the consulting firm KPMG has been engaged to provide leadership and expertise to the Oglethorpe
staff developing the contingency plans.KPMG. The contingency
plans were completed as of July 31, 1999 and will continue to be evaluated,
tested and implemented throughout 1999. The contingency plans also focus on
non-compliance by material third parties and 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 the contingency planning process is to keep any service
interruptions to a minimum and of short duration and to avoid disruptions in its
billing or other management processes. Oglethorpe may incur additional costs as
a result of implementing 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 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 "COMPETITION" and
"YEAR 2000" herein, "Miscellaneous--COMPETITION"
in Item 2 of Oglethorpe's Quarterly Report on Form 10-Q for the quarterly period
ended March 31, 1999 and
15
"CERTAIN FACTORS AFFECTING THE ELECTRIC UTILITY INDUSTRY" in Item 1 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.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Oglethorpe's market risks have not changed materially from the
market risks reported in theOglethorpe's 1998 Annual Report on Form 10-K.
1716
PART II - OTHER INFORMATION
ITEM 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 FORM 8-K
(a) EXHIBITS
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.NUMBER DESCRIPTION
------ -----------
27.1 Financial Data Schedule (for SEC use only).
(b) REPORTS ON FORM 8-K
No reports on Form 8-K were filed by Oglethorpe for the quarter ended March 31,June 30,
1999.
1817
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: May 14,August 13, 1999 By: /S//s/ JACK L. KING
-----------------------------------------------------------------------------------------
Jack L. King
President and Chief Executive Officer
(Principal Executive Officer)
Date: May 14,August 13, 1999 /S//s/ MAC F. OGLESBY
-----------------------------------------------------------------------------------------
Mac F. Oglesby
Treasurer
(Principal Financial Officer)
Date: May 14,August 13, 1999 /S//s/ THOMAS A. SMITH
-----------------------------------------------------------------------------------------
Thomas A. Smith
Senior Vice President and Chief Financial Officer
(Principal Financial Officer)
Date: May 14,August 13, 1999 /S//s/ WILLIE B. COLLINS
-----------------------------------------------------------------------------------------
Willie B. Collins
Controller
(Chief Accounting Officer)
1918