Item 1. Business.
OVERVIEW OF OPERATIONS
LG&E Energy, incorporated November 14, 1989, is a diversified energy-services holding company with four direct operating subsidiaries: LG&E, KU, Capital Corp., and LEM. The Company's domestic regulated operations are conducted by LG&E and KU.
The Company and its subsidiaries currently are exempt from all provisions, except Section 9(a)(2), of the Public Utility Holding Company Act of 1935 (the "Holding Company Act") on the basis that the Company, LG&E and KU are incorporated in the same state and their business is predominately intrastate in character and carried on substantially in the state of incorporation.
The Company is not a public utility under the laws of the Commonwealths of Kentucky or of Virginia and is not subject to regulation as such by the Kentucky Commission or the Virginia Commission. See LG&E - Rates and Regulation and KU - Rates and Regulation for descriptions of the regulation of LG&E and KU by the Kentucky Commission, and of KU by the Virginia Commission and FERC, which includes the ability to regulate certain intercompany transactions between LG&E, KU and the Company, including the Company's non-utility subsidiaries.
POWERGEN TRANSACTION
On February 28, 2000, the Company announced that its Board of Directors accepted an offer to be acquired by PowerGen for cash of approximately $3.2 billion or $24.85 per share and the assumption of $2.2 billion of the Company's debt. Pursuant to the acquisition agreement, among other things, LG&E Energy will become a wholly owned subsidiary of PowerGen and its U.S. headquarters. The Utility Operations of the Company will continue their separate identities and serve customers in Kentucky and Virginia under their present names. The preferred stock and debt securities of the Utility Operations will not be affected by this transaction. The acquisition is expected to close 9 to 12 months from the announcement, shortly after all of the conditions to consummation of the acquisition are met. Those conditions include, without limitation, the approval of the holders of a majority of the outstanding shares of common stock of each of LG&E Energy and PowerGen, the receipt of all necessary governmental approvals and the making of all necessary governmental filings, including approvals of various regulators in Kentucky and Virginia under state utility laws, the approval of the FERC under the FPA, the approval of the SEC under the PUHCA of 1935, and the filing of requisite notifications with the Federal Trade Commission and the Department of Justice under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, and the expiration of all applicable waiting periods thereunder. Shareholder meetings to vote upon the approval of the acquisition are expected to be held during the second quarter of 2000 for both LG&E Energy and PowerGen. During the first quarter of 2000, the Company expensed approximately $1.0 million relating to the PowerGen transaction. The foregoing description of the acquisition does not purport to be complete and is qualified in its entirety by reference to LG&E Energy's current reports on Form 8-K, filed February 29, 2000, with the SEC.
MERGER WITH KU ENERGY CORPORATION
Effective May 4, 1998, following the receipt of all required state and federal regulatory approvals, LG&E Energy and KU Energy merged, with LG&E Energy as the surviving corporation. The accompanying consolidated financial statements reflect the accounting for the merger as a pooling of interests and are presented as if the companies were combined as of the earliest period presented. However, the financial information is not necessarily indicative of the results of operations, financial position or cash flows that would have occurred had the merger been consummated for the periods for which it is given effect, nor is it necessarily
indicative of future results of operations, financial position, or cash flows. The financial statements reflect the conversion of each outstanding share of KU Energy common stock into 1.67 shares of LG&E Energy common stock. The outstanding preferred stock of LG&E, a subsidiary of LG&E Energy, and KU, a subsidiary of KU Energy, were not affected by the Merger. See Note 2 of LG&E Energy's Notes to Financial Statements under Item 8.
DISCONTINUANCE OF MERCHANT ENERGY TRADING AND SALES BUSINESS
Effective June 30, 1998, the Company discontinued its merchant energy trading and sales business. This business consisted primarily of a portfolio of energy marketing contracts entered into in 1996 and early 1997, nationwide deal origination and some level of speculative trading activities, which were not directly supported by the Company's physical assets. The Company's decision to discontinue these operations was primarily based on the impact that volatility and rising prices in the power market had on its portfolio of energy marketing contracts. Exiting the merchant energy trading and sales business enabled the Company to focus on optimizing the value of physical assets it owns or controls, and reduced the earnings impact on continuing operations of extreme market volatility in its portfolio of energy marketing contracts. The Company continues to settle commitments that obligate it to buy and sell natural gas and electric power. If the Company is unable to dispose of these commitments or assets it will continue to meet its obligations under the terms of the contracts. The Company, however, has maintained sufficient market knowledge, risk management skills, technical systems and experienced personnel to maximize the value of power sales from physical assets it owns or controls, including LG&E, KU and WKE.
As a result of the Company's decision to discontinue its merchant energy trading and sales activity, and the initial decision to sell the associated gas gathering and processing business, the Company recorded an after-tax loss on disposal of discontinued operations of $225 million in the second quarter of 1998. The loss on disposal of discontinued operations resulted primarily from several fixed-price energy marketing contracts entered into in 1996 and early 1997, including the Company's long-term contract with OPC. Other components of the write-off included costs relating to certain peaking options, goodwill associated with the Company's 1995 purchase of merchant energy trading and sales operations and exit costs.
At the time the Company decided to discontinue its merchant energy trading and sales business, it also decided to sell its natural gas gathering and processing business. Effective June 30, 1999, the Company decided to retain this business. The accompanying financial statements reflect the reclassification of the natural gas gathering and processing business as continuing operations for all periods presented. Approximately $800,000 of net losses charged to the loss on disposal of discontinued operations was reclassified to continuing operations in the accompanying income statement in each of 1999 and 1998 related to the natural gas gathering and processing business. See Note 4 of LG&E Energy's Notes to Financial Statements under Item 8 for more information.
In the fourth quarter of 1999, the Company received an adverse decision from the arbitration panel considering its contract dispute with OPC, which was commenced by the Company in April 1998. As a result of this adverse decision, higher than anticipated commodity prices, increased load demands, and other factors, the Company increased its after-tax accrued loss on disposal of discontinued operations by $175 million. The additional write-off included costs related to the remaining commitments in its portfolio and exit costs expected to be incurred to serve those commitments. Although the Company used what it believes to be appropriate estimates for future energy prices, among other factors, to calculate the net realizable value of discontinued operations, there are inherent limitations in models to accurately predict future commodity prices, load demands and other events that could impact the amounts recorded by the Company. See Notes 3 and 18 of LG&E Energy's Notes to Financial Statements under Item 8.
The Company reclassified its financial statements for prior periods to present the operating results, financial position and cash flows of the merchant energy trading and sales business as discontinued operations. See Notes 1, 3 and 4 of LG&E Energy's Notes to Financial Statements under Item 8 for more information.
CRC ACQUISITION
In July 1999, the Company purchased 100% of the outstanding common stock of CRC for initial consideration of $45.6 million and retirement of approximately $35.3 million in CRC debt. CRC, based in Houston, Texas, is a provider of specialized equipment and services used in the construction and rehabilitation of gas and oil transmission pipelines. The purchase agreement provides for future annual earn-out payments to the previous owners based on CRC's meeting certain financial targets over the period ending March 31, 2002, and, under certain circumstances, a change in control of LG&E Energy may accelerate the earnout. The acquisition agreement capped the total of these payments at $34.3 million. The Company accounted for the acquisition using the purchase method and recorded goodwill of approximately $42.1 million. Additional goodwill will be recorded contingent upon future earn-out payments. Goodwill is being amortized over a period of twenty years. See Note 2 of LG&E Energy's Notes to Financial Statements under Item 8.
GAS BAN ACQUISITION
In March 1999, the Company acquired an indirect 20% ownership interest in Gas BAN, a natural gas distribution company that serves 1.1 million customers in the northern portion of the province of Buenos Aires, Argentina. The purchase price totaled $74.3 million, including transaction costs, which has been reflected in investments in unconsolidated ventures in the accompanying balance sheet. The Company accounted for the acquisition using the purchase method, and records its share of earnings using the equity method. The purchase price exceeded the underlying equity in Gas BAN by $13.0 million. The Company allocated this difference to the assets and liabilities acquired based on their preliminary estimated fair values. See Note 2 of LG&E Energy's Notes to Financial Statements under Item 8.
LEASE OF BIG RIVERS FACILITIES
In July 1998, the Company closed the transaction to lease the generating assets of Big Rivers. Under the 25-year operating lease, WKE operates Big Rivers' coal-fired facilities, a combustion turbine and operates and maintains the Station Two generating facility of Henderson. The combined generating capacity of these facilities is approximately 1,700 Mw, net of the Henderson's capacity and energy needs from Station Two. In related transactions, power is supplied to Big Rivers at contractual prices over the term of the lease to meet the needs of three member distribution cooperatives and their retail customers, including major western Kentucky aluminum smelters. Excess generating capacity is available to WKE to market throughout the region. In connection with these transactions, WKE has undertaken to bear certain of the future capital requirements of those generating assets, certain defined environmental compliance costs and other obligations. Big Rivers' personnel at the plants became employees of WKE upon the completion of the transactions. See Note 5 of LG&E Energy's Notes to Financial Statements under Item 8.
LOUISVILLE GAS AND ELECTRIC COMPANY
General
Incorporated on July 2, 1913, LG&E is a regulated public utility that supplies natural gas to approximately 295,000 customers and electricity to approximately 366,000 customers in Louisville and adjacent areas in Kentucky. LG&E's service area covers approximately 700 square miles in 17 counties and has an estimated population of one million. Included in this area is the Fort Knox Military Reservation, to which LG&E
transports gas and provides electric service, but which maintains its own distribution systems. LG&E also provides gas service in limited additional areas. LG&E's coal-fired electric generating plants, which are all equipped with systems to reduce sulfur dioxide emissions, produce most of LG&E's electricity. The remainder is generated by a hydroelectric power plant and combustion turbines. Underground natural gas storage fields help LG&E provide economical and reliable gas service to customers. See Item 2, Properties.
For the year ended December 31, 1999, 82% of total operating revenues was derived from electric operations and 18% from gas operations. Electric and gas operating revenues and the percentages by classes of service on a combined basis for this period were as follows:
(Thousands of $) Electric Gas Combined % Combined -------- --- -------- ----------
Residential $215,019 $103,655 $318,674 44% Commercial 176,692 38,627 215,319 30 Industrial 112,038 10,401 122,439 17 Public authorities 56,042 9,013 65,055 9 -------- -------- -------- --- Total retail 559,791 161,696 721,487 100% === Wholesale sales 221,336 8,118 229,454 Gas transported - net - 6,350 6,350 Provision for rate refunds (1,735) - (1,735) Miscellaneous 11,278 1,415 12,693 -------- -------- -------- Total $790,670 $177,579 $968,249 ======== ======== ========
See Note 14 of LG&E's Notes to Financial Statements and Note 20 of LG&E Energy's Notes to Financial Statements under Item 8 for financial information concerning segments of business for the three years ended December 31, 1999.
Electric Operations
The sources of LG&E's electric operating revenues and the volumes of sales for the three years ended December 31, 1999, were as follows:
1999 1998 1997 ---- ---- ----
ELECTRIC OPERATING REVENUES (Thousands of $): Residential $215,019 $213,476 $205,137 Small commercial and industrial 79,261 76,304 72,769 Large commercial 97,431 94,650 90,131 Large industrial 112,038 113,372 110,652 Public authorities 56,042 55,075 53,412 -------- -------- -------- Total retail 559,791 552,877 532,101 Wholesale sales 221,336 99,340 70,942 Provision for rate refunds (1,735) (4,500) - Miscellaneous 11,278 10,794 11,489 -------- -------- -------- Total $790,670 $658,511 $614,532 ======== ======== ========
ELECTRIC SALES (Thousands of Mwh): Residential 3,680 3,534 3,302 Small commercial and industrial 1,218 1,156 1,108 Large commercial 2,072 1,977 1,880 Large industrial 3,047 3,097 3,054 Public authorities 1,187 1,140 1,105 -------- -------- -------- Total retail 11,204 10,904 10,449 Wholesale sales 8,428 4,970 3,800 -------- -------- -------- Total 19,632 15,874 14,249 ======== ======== ========
LG&E uses efficient coal-fired boilers, fully equipped with sulfur dioxide removal systems, to generate most of its electricity. LG&E's system wide emission weighted-average rate for sulfur dioxide in 1999 was approximately .9 lbs./Mmbtu of heat input, which is significantly below the Year 2000 Phase II limit of 1.2 lbs./Mmbtu established by the Act.
The 1999 maximum local peak load of 2,612 Mw occurred on Friday, July 30, 1999, when the temperature at the time was 106 degrees F. Prior to 1999, the record local peak load was 2,427 Mw (set on August 25, 1998).
The electric utility business is affected by seasonal weather patterns. As a result, operating revenues (and associated operating expenses) are not generated evenly throughout the year. See LG&E's Results of Operations under Item 7.
LG&E's current reserve margin is 12%. At December 31, 1999, LG&E owned steam and combustion turbine generating facilities with a capacity of 2,637 Mw and an 80 Mw hydroelectric facility on the Ohio River. See Item 2, Properties.
LG&E is a participating owner with 14 other electric utilities of Ohio Valley Electric Corporation whose primary customer is the Portsmouth Area uranium-enrichment complex of the U.S. Department of Energy at Piketon, Ohio. LG&E has direct interconnections with 11 utility companies in the area and has agreements with each interconnected utility for the purchase and sale of capacity and energy. LG&E also has agreements with an increasing number of entities throughout the United States for the purchase and/or sale of capacity and energy and for the utilization of their bulk transmission system.
Gas Operations
The sources of LG&E's gas operating revenues and the volumes of sales for the three years ended December 31, 1999, were as follows:
1999 1998 1997 ---- ---- ----
GAS OPERATING REVENUES (Thousands of $): Residential $103,655 $113,430 $139,967 Commercial 38,627 40,888 52,440 Industrial 10,401 11,969 17,892 Public authorities 9,013 8,884 12,052 -------- -------- -------- Total retail 161,696 175,171 222,351 Wholesale sales 8,118 8,720 - Gas transported - net 6,350 6,926 6,997 Miscellaneous 1,415 728 1,663 -------- -------- -------- Total $177,579 $191,545 $231,011 ======== ======== ========
GAS SALES (Millions of cu. ft.): Residential 21,565 20,040 24,038 Commercial 9,033 8,448 10,212 Industrial 2,781 2,860 3,948 Public authorities 2,228 1,967 2,467 -------- -------- -------- Total retail 35,607 33,315 40,665 Wholesale sales 3,881 3,880 - Gas transported 14,014 13,027 13,452 -------- -------- -------- Total 53,502 50,222 54,117 ======== ======== ========
The gas utility business is affected by seasonal weather patterns. As a result, operating revenues (and associated operating expenses) are not generated evenly throughout the year. See LG&E's Results of Operations under Item 7.
LG&E has underground natural gas storage fields that help provide economical and reliable gas service to ultimate consumers. By using gas storage fields strategically, LG&E can buy gas when prices are low, store it, and retrieve the gas when demand is high. Currently, LG&E buys competitively priced gas from several large producers under contracts of varying duration. By purchasing from multiple suppliers and storing any excess gas, LG&E is able to secure favorably priced gas for its customers. Without storage capacity, LG&E would be forced to buy additional gas when customer demand increases, which is usually when the price is highest.
A number of industrial customers purchase their natural gas requirements directly from alternate suppliers for delivery through LG&E's distribution system. Generally, transportation of natural gas for LG&E's customers does not have an adverse effect on earnings because of the offsetting decrease in gas supply expenses. Transportation rates are designed to make LG&E economically indifferent as to whether gas is sold or merely transported.
The all-time maximum day gas sendout of 545,000 Mcf occurred on Sunday, January 20, 1985, when the average temperature for the day was -11 degrees F. During 1999, the maximum day gas sendout was 511,000 Mcf, occurring on January 4, when the average temperature for the day was 10 degrees F. Supply on that day consisted of 230,000 Mcf from purchases, 222,000 Mcf delivered from underground storage, and 59,000 Mcf transported for industrial customers. For a further discussion, see Gas Supply under Item 1.
Rates and Regulation
The Kentucky Commission has regulatory jurisdiction over the rates and service of LG&E and over the issuance of certain of its securities. The Kentucky Commission has the ability to examine the rates LG&E charges its retail customers at any time. LG&E is a "public utility" as defined in the FPA, and is subject to the jurisdiction of the Department of Energy and the FERC with respect to the matters covered in such Act, including the sale of electric energy at wholesale in interstate commerce. In addition, the FERC has sole jurisdiction over the issuance by LG&E of short-term securities.
For a discussion of current regulatory matters, see Rates and Regulation for LG&E and LG&E Energy Corp. under Item 7 and Note 3 of LG&E's Notes to Financial Statements and Note 6 of LG&E Energy's Notes to Financial Statements under Item 8.
LG&E's electric rates contain a FAC, whereby increases and decreases in the cost of fuel for electric generation are reflected in the rates charged to all electric customers. The Kentucky Commission requires public hearings at six-month intervals to examine past fuel adjustments, and at two-year intervals to review past operations of the fuel clause and transfer of the then current fuel adjustment charge or credit to the base charges. The Kentucky Commission also requires that electric utilities, including LG&E, file certain documents relating to fuel procurement and the purchase of power and energy from other utilities.
LG&E's gas rates contain a GSC, whereby increases or decreases in the cost of gas supply are reflected in LG&E's rates, subject to approval of the Kentucky Commission. The GSC procedure prescribed by order of the Kentucky Commission provides for quarterly rate adjustments to reflect the expected cost of gas supply in that quarter. In addition, the GSC contains a mechanism whereby any over- or under-recoveries of gas supply cost from prior quarters will be refunded to or recovered from customers through the adjustment factor determined for subsequent quarters.
Integrated resource planning regulations in Kentucky require LG&E and the other major utilities to make triennial filings with the Kentucky Commission of various historical and forecasted information relating to forecasted load, capacity margins and demand-side management techniques.
Pursuant to Kentucky law, the Kentucky Commission has established the boundaries of the service territory or area of each retail electric supplier in Kentucky (including LG&E), other than municipal corporations, within which each such supplier has the exclusive right to render retail electric service.
Construction Program and Financing
LG&E's construction program is designed to ensure that there will be adequate capacity and reliability to meet the electric and gas needs of its service area. These needs are continually being reassessed and appropriate revisions are made, when necessary, in construction schedules. LG&E's estimates of its construction expenditures can vary substantially due to numerous items beyond LG&E's control, such as changes in rates, economic conditions, construction costs, and new environmental or other governmental laws and regulations.
During the five years ended December 31, 1999, gross property additions amounted to $645 million. Internally generated funds and external financings for the five-year period were sufficient to provide for all of these gross additions. The gross additions during this period amounted to approximately 21% of total utility plant at December 31, 1999, and consisted of $493 million for electric properties and $152 million for gas properties. Gross retirements during the same period were $116 million, consisting of $88 million for electric properties and $28 million for gas properties.
Coal Supply
Over 90% of LG&E's present electric generating capacity is coal-fired, the remainder being made up of a hydroelectric plant and combustion turbine peaking units fueled by natural gas and oil. Coal will be the predominant fuel used by LG&E in the foreseeable future, with natural gas and oil being used for peaking capacity and flame stabilization in coal-fired boilers or in emergencies. LG&E has no nuclear generating units and has no plans to build any in the foreseeable future. LG&E has entered into coal supply agreements with various suppliers for coal deliveries for 1999 and beyond. LG&E normally augments its coal supply agreements with spot market purchases which, during 1999, were about 5% of total purchases. LG&E has a coal inventory policy which it believes provides adequate protection under most contingencies. LG&E had on hand at December 31, 1999, a coal inventory of approximately 816,000 tons, or a 43-day supply.
LG&E expects, for the foreseeable future, to continue purchasing most of its coal, which has a sulfur content in the 2%-4.5% range, from western Kentucky, southwest Indiana, West Virginia and Ohio. The abundant supply of this relatively low priced coal, combined with present and future desulfurization technologies, is expected to enable LG&E to continue to provide adequate electric service in a manner acceptable under existing environmental laws and regulations.
Coal is delivered for LG&E's Mill Creek plant by rail and barge; Trimble County plant by barge and Cane Run plant by rail.
The average delivered cost of coal purchased by LG&E, per ton and per Mmbtu, for the periods shown were as follows:
1999 1998 1997 ---- ---- ----
Per ton $21.49 $22.38 $21.66 Per Mmbtu .95 .98 .94
The delivered cost of coal is expected to decrease during 2000.
Gas Supply
LG&E purchases transportation services from Texas Gas and Tennessee. LG&E purchases natural gas supplies from multiple sources under contracts for varying periods of time.
During 2000, Texas Gas filed with FERC for a change in its rates as required under the settlement in its last rate case. LG&E plans to participate in that and other proceedings, as appropriate. The requested increase, the resolution of that case, and the timing and amounts of refunds, if any, are not known at this time.
LG&E transports on the Texas Gas system under NNS and FT rates. During the winter months, LG&E has 184,900 Mmbtu per day in NNS. LG&E's summer NNS levels are 60,000 Mmbtu per day and its summer FT levels are 54,000 Mmbtu per day. Each of these NNS and FT agreements with Texas Gas expire in equal portions in 2001, 2003, and 2005. LG&E also transports on the Tennessee system under Tennessee's Rate FT-A. LG&E's contract levels with Tennessee are 51,000 Mmbtu per day annually. The FT-A agreement with Tennessee expires 2002.
LG&E also has a portfolio of supply arrangements with various suppliers in order to meet its firm sales obligations. These gas supply arrangements include pricing provisions that are market-responsive. These firm supplies, in tandem with pipeline transportation services, provide the reliability and flexibility necessary to serve LG&E's
customers.
LG&E operates five underground gas storage fields with a current working gas capacity of 14.6 million Mcf. Gas is purchased and injected into storage during the summer season and is then withdrawn to supplement pipeline supplies to meet the gas-system load requirements during the winter heating season.
The estimated maximum deliverability from storage during the early part of the 1999-2000 heating season was approximately 373,000 Mcf per day. Deliverability decreases during the latter portion of the heating season as the storage inventory is reduced by seasonal withdrawals.
The average cost per Mcf of natural gas purchased by LG&E was $2.99 in 1999, $3.05 in 1998 and $3.46 in 1997.
Environmental Matters
Protection of the environment is a major priority for LG&E. LG&E engages in a variety of activities within the jurisdiction of federal, state, and local regulatory agencies. Those agencies have issued LG&E permits for various activities subject to air quality, water quality, and waste management laws and regulations. For the five-year period ending with 1999, expenditures for pollution control facilities represented $124 million or 19% of total construction expenditures. For a discussion of environmental matters, see Rates and Regulation for LG&E and LG&E Energy Corp. under Item 7 and Note 12 of LG&E's Notes to Financial Statements and Note 18 of LG&E Energy's Notes to Financial Statements under Item 8.
Competition
In the last several years, LG&E has taken many steps to prepare for the expected increase in competition in its industry, including a reduction in the number of employees; aggressive cost cutting; write-offs of previously deferred expenses; an increase in focus on commercial, industrial and residential customers; an increase in employee involvement and training; a major realignment and formation of new business units, and continuous modifications of its organizational structure. LG&E could take additional steps to better position itself for competition in the future.
KENTUCKY UTILITIES COMPANY
General
KU was incorporated in Kentucky in 1912 and incorporated in Virginia in 1991. KU is a public utility engaged in producing, transmitting and selling electric energy. KU provides electric service to about 458,000 customers in over 600 communities and adjacent suburban and rural areas in 77 counties in central, southeastern and western Kentucky, and to about 29,000 customers in 5 counties in southwestern Virginia. In Virginia, KU operates under the name Old Dominion Power Company. KU operates under appropriate franchises in substantially all of the 160 Kentucky incorporated municipalities served. No franchises are required in unincorporated Kentucky or Virginia communities. The lack of franchises is not expected to have a material adverse effect on KU's operations. KU also sells wholesale electric energy to 12 municipalities.
Electric Operations
The sources of KU's electric operating revenues and the volumes of sales for the three years ended December 31, 1999, were as follows:
1999 1998 1997 ---- ---- ----
ELECTRIC OPERATING REVENUES (Thousands of $): Residential $ 242,304 $ 238,566 $ 231,824 Commercial 160,895 158,340 150,794 Industrial 154,460 154,475 146,801 Mine Power 28,792 31,620 34,541 Public authorities 58,500 58,740 56,243 --------- --------- --------- Total - ultimate consumers 644,951 641,741 620,203 Wholesale sales 286,595 179,118 87,330 Provision for rate refunds (5,900) (21,500) -- Miscellaneous 11,664 10,755 8,904 --------- --------- --------- Total $ 937,310 $ 810,114 $ 716,437 ========= ========= =========
ELECTRIC SALES (Thousands of Mwh): Residential 5,447 5,247 5,061 Commercial 3,760 3,644 3,422 Industrial 4,911 4,747 4,464 Mine Power 752 838 926 Public authorities 1,437 1,424 1,355 --------- --------- --------- Total - ultimate consumers 16,307 15,900 15,228 Wholesale sales 10,188 7,224 3,397 --------- --------- --------- Total 26,495 23,124 18,625 ========= ========= =========
The electric utility business is affected by seasonal weather patterns. As a result, operating revenues (and associated operating expenses) are not generated evenly throughout the year. See KU's Results of Operations under Item 7.
At December 31, 1999, KU owned steam and combustion turbine generating facilities with a capacity of 3,898 Mw and a 24 Mw hydroelectric facility. See Item 2, Properties. KU obtains power from other utilities under bulk power purchase and interchange contracts. At December 31, 1999, KU's system capability, including purchases from others, was 4,229 Mw. On July 30, 1999, a record local peak load, on a one-hour integrated basis, was set at 3,764 Mw.
Under a contract expiring in 2020 with OMU, KU has agreed to purchase from OMU the surplus output of the 150-Mw and 250-Mw generating units at OMU's Elmer Smith station. Purchases under the contract are made under a contractual formula which has resulted in costs which were and are expected to be comparable to the cost of other power purchased or generated by KU. Such power constituted about 7% of KU's net system output during 1999. See Note 11 of KU's Notes to Financial Statements and Note 18 of LG&E Energy's Notes to Financial Statements under Item 8.
KU owns 20% of the common stock of EEI, which owns and operates a 1,000-Mw generating station in southern Illinois. KU's entitlement is 20% of the available capacity of the station. Purchases from EEI are made under a contractual formula which has resulted in costs which were and are expected to be comparable to the cost of other power purchased or generated by KU. Such power constituted about 6% of KU's net system output in 1999. See Note 11 of KU's Notes to Financial Statements and Note 18 of LG&E Energy's Notes to
Financial Statements under Item 8.
Rates and Regulation
The Kentucky Commission and the Virginia Commission have regulatory jurisdiction over KU's retail rates and service, and over the issuance of certain of its securities. FERC has jurisdiction under the FPA over certain of the electric utility facilities and operations, wholesale sale of power and related transactions and accounting practices of KU, and in certain other respects as provided in the FPA. FERC has classified KU as a "public utility" as defined in the FPA. By reason of owning and operating a small amount of electric utility property in one county in Tennessee (having a gross book value of about $225,000) from which KU serves five customers, KU is subject to the jurisdiction of the TRA. In addition, the FERC has sole jurisdiction over the issuance by KU of short-term securities.
For a discussion of current regulatory matters, see Rates and Regulation for KU and LG&E Energy Corp. under Item 7 and under Note 3 of KU's Notes to the Financial Statements and Note 6 of LG&E Energy's Notes to Financial Statements under Item 8.
KU's electric rates contain a FAC, whereby increases and decreases in the cost of fuel for electric generation are reflected in the rates charged to all electric customers. The Kentucky Commission requires public hearings at six-month intervals to examine past fuel adjustments, and at two-year intervals to review past operations of the fuel clause and transfer of the then current fuel adjustment charge or credit to the base charges. The Kentucky Commission also requires that electric utilities, including KU, file certain documents relating to fuel procurement and the purchase of power and energy from other utilities. The FAC mechanism for Virginia customers uses an average fuel cost factor based primarily on projected fuel costs. The fuel cost factor may be adjusted annually for over- or under collections of fuel costs from the previous year.
Integrated resource planning regulations in Kentucky require KU and the other major utilities to make triennial filings with the Kentucky Commission of various historical and forecasted information relating to forecasted load, capacity margins and demand-side management techniques.
Pursuant to Kentucky law, the Kentucky Commission has established the boundaries of the service territory or area of each retail electric supplier in Kentucky (including KU), other than municipal corporations, within which each such supplier has the exclusive right to render retail electric service.
The Virginia Commission requires each Virginia utility to make annual filings of either a base rate change or an Annual Informational Filing consisting of a set of standard financial schedules. These filings are subject to review by the Staff. The Staff issues a Staff Report, which includes any findings or recommendations to the Virginia Commission relating to the individual utility's financial performance during the historic 12-month period, including previously accepted adjustments. The Staff Report can lead to an adjustment in rates.
As a result of its ownership in EEI, KU is considered a holding company under the Holding Company Act. KU however is presently exempt from all the provisions of the Holding Company Act, except Section 9(a)(2) thereof (which relates to the acquisition of securities of public utility companies), by virtue of the exemption granted by an order of the SEC.
Construction Program and Financing
KU's construction program is designed to ensure that there will be adequate capacity and reliability to meet the electric needs of its service area. These needs are continually being reassessed and appropriate revisions are made, when necessary, in construction schedules. KU's estimates of its construction expenditures can vary substantially
due to numerous items beyond KU's control, such as changes in rates, economic conditions, construction costs, and new environmental or other governmental laws and regulations.
During the five years ended December 31, 1999, construction expenditures aggregated about $596 million, which included five combustion turbine peaking units. Three 126-Mw units were placed into commercial operation in 1995 and 1996. Two 164-Mw units, which are jointly owned with LG&E, were put into commercial operation in August 1999.
Coal Supply
Coal-fired generating units provided more than 98% of KU's net kilowatt-hour generation for 1999. The remainder of KU's net generation for 1999 was provided by oil and/or natural gas burning units and hydroelectric plants. The average delivered cost of coal purchased per Mmbtu and the percentage of spot coal purchases for the periods indicated were as follows:
1999 1998 1997 ---- ---- ----
Per ton $ 26.65 $ 26.97 $ 27.97 Per Mmbtu - all sources $ 1.11 $ 1.12 $ 1.15 Per Mmbtu - spot purchases only $ 1.11 $ 1.10 $ 1.12 Spot purchases as % of all sources 53% 42% 34%
The price of coal is expected to decrease slightly during 2000.
KU maintains its fuel inventory at levels estimated to be necessary to avoid operational disruptions at its coal-fired generating units. Reliability of coal deliveries can be affected from time to time by a number of factors, including fluctuations in demand, coal mine labor issues and other supplier or transporter operating difficulties.
KU believes there are adequate reserves available to supply its existing base-load generating units with the quantity and quality of coal required for those units throughout their useful lives. KU intends to meet a portion of its coal requirements with three-year or shorter contracts. As part of this strategy, KU will continue to negotiate replacement contracts as contracts expire. KU does not anticipate any problems negotiating new contracts for future coal needs. The balance of coal requirements will be met through spot purchases. KU had on hand at December 31, 1999, a coal inventory of approximately 1,063,000 tons, or a 48 day supply.
KU expects, for the foreseeable future, to continue purchasing most of its coal, which has a sulfur content in the .7% - 3.5% range, from western and eastern Kentucky, West Virginia, southwest Indiana and Pennsylvania.
Coal for Ghent is delivered by barge. Deliveries to the Tyrone, Green River and Pineville locations are by truck. Delivery to E.W. Brown is by rail.
KU has no long-term contracts in place for the purchase of natural gas for its combustion turbine peaking units. KU has met its gas requirements through spot purchases and does not anticipate encountering any significant problems acquiring an adequate supply of fuel necessary to operate its peaking units.
Environmental Matters
Protection of the environment is a major priority for KU. KU engages in a variety of activities within the jurisdiction of federal, state, and local regulatory agencies. Those agencies have issued KU permits for various activities subject to air quality, water quality, and waste management laws and regulations. For the five year
period ending with 1999, expenditures for pollution control facilities represented $42 million or 7% of total construction expenditures. See Note 11 of KU's Notes to Financial Statements and Note 18 of LG&E Energy's Notes to Financial Statements under Item 8.
Competition
KU has taken many steps to prepare for the expected increase in competition in its industry, including a reduction in the number of employees; aggressive cost cutting; an increase in focus on not only commercial and industrial customers, but residential customers as well; an increase in employee involvement and training; and continuous modifications of its organizational structure. KU could take additional steps like these to better position itself for competition in the future.
LG&E CAPITAL CORP. AND OTHER
Capital Corp., the holding company for all the Company's non-utility investments other than trading operations, was formed on September 5, 1997, when the Company merged two of its former direct subsidiaries, Energy Systems and Gas Systems, and renamed the company LG&E Capital Corp. On July 24, 1998, KU Capital, a former subsidiary of KU Energy, was merged into Capital Corp., with the latter as the survivor corporation.
As previously discussed in item 1 under Discontinuance of Merchant Energy Trading and Sales Business, effective June 30, 1998, the Company decided to discontinue its merchant energy trading and sales business, and it decided to sell its natural gas gathering and processing business. Effective June 30, 1999, the Company decided to retain the natural gas gathering and processing business. For a more detailed discussion of the discontinuance of the Company's merchant energy trading and sales business, and the decision to retain the natural gas gathering and processing business, see Discontinued Operations under this Item, and Notes 3, 4 and 18 of LG&E Energy's Notes to Financial Statements under Item 8.
Capital Corp. conducts its operations through three principal business segments: Power Operations, Western Kentucky Energy and Argentine Gas Distribution. Capital Corp. is also engaged in other non-utility activities including: providing specialized equipment and services used in construction and rehabilitation of gas and oil transmission pipelines; the gathering, processing, storing and transportation of natural gas; commercial and retail initiatives designed to assess the energy and utility needs of large commercial and industrial entities; providing maintenance and repair services for customers' major household appliances; and, the asset optimization of the Company's generation assets. See Notes 2, 5, 9, 10, 18 and 20 of LG&E Energy's Notes to Financial Statements under Item 8. LEM conducts asset-based energy marketing on behalf of the Company's utility and non-utility operations.
POWER OPERATIONS
General
Capital Corp.'s Power Operations develop, operate, maintain and own domestic and international power generation facilities that sell electric and steam energy to utility and industrial customers. Power Operations currently has domestic ownership interests in projects capable of generating nearly 600 Mw of electric power in North Carolina, Virginia, California, Minnesota, Texas and Washington, and international ownership interest in a windpower generating facility in Tarifa, Spain, and ownership interests in three combustion turbines. Ownership interests in each of these projects and the revenues from the sale of electricity and steam are pledged as security to the lenders which provided the financing. See Item 2, Properties, for a listing of the Power Operations' projects.
In March 1999, LG&E Westmoreland - Rensselaer, in which Power Operations owned a 50% interest, sold the assets of the Rensselaer cogeneration facility. This transaction resulted in an after-tax gain for Power Operations of approximately $8.9 million.
In June 1998, Power Operations entered into a partnership with Columbia Electric Corporation for the development of a natural gas-fired cogeneration project in Gregory, Texas, providing electricity and steam equivalent of 550 Mw. Construction commenced in August 1998 and non-recourse financing for a majority of the construction and other costs was obtained in November 1998. The project will sell steam and a portion of its electric output to Reynolds Metals Company. A medium-term fixed-price contract has also been entered into with a third party for a portion of the remaining electric output. The project is expected to begin commercial operation in the summer of 2000. The Company's equity contribution is expected to be approximately $30 to $35 million in connection with its 50% interest in the project.
In February 1998, Power Operations sold its interest in a 114-Mw natural gas-fired power plant in North Central Argentina. The transaction resulted in a $2.8 million pre-tax loss.
Fuel Supply
Power Operations operates five coal fired and three wind plants. See Item 2, Properties. Coal supply needed by Power Operations is generally purchased under long-term contracts expiring at various times from 2008 through 2014. Each contract has two five-year renewal options. All coal is delivered by rail.
Customer Base
Each project has long-term power purchase agreements with a single power purchaser, except one of the Tenaska Limited Partnerships which has two. The power purchasers are VEPCO for Southampton, Altavista, and Hopewell in Virginia and ROVA I and ROVA II in North Carolina; Southern California Edison Co. for WPP 93 in California; Northern States Power Company for WPP 93 in Minnesota; Lower Colorado River Authority for WPP 94, Brazos Electric Power Cooperative for TLP, Texas Utilities Electric Company for TLP and Campbell Soup for TLP in Texas; Puget Sound Power & Light for TLP in Washington; and Compania Sevillana de Electricidad for Tarifa in Spain. WPP 94 also sells excess power to Texas Utilities. See Item 2, Properties, for a listing of Power Operations projects.
In August 1999, four combustion turbines previously leased to Portland General Electric Company in Oregon were sold to that company at a pre-tax gain of $.8 million. Capital Corp. owned 100% of two of these turbines and 49% ownership interest in the others.
In October, 1999, one combustion turbine previously leased to Puget Sound Power & Light Company in Washington was sold to that company at a pre-tax gain of $2.3 million. Capital Corp. held a 49% ownership interest in this turbine.
Throughout 1999, three combustion turbines were leased to AP&L. Capital Corp. holds a 49% interest in these turbines through the CEC-APL, L.P. partnership. Upon expiration of the AP&L leveraged lease, the $9 million residual value of the turbines was reclassified to Investment in Unconsolidated Affiliates. See Note 9 of LG&E Energy's Notes to Financial Statements under Item 8. In February 2000, Power Operations entered into an agreement to sell its interest to its co-partner in the project.
Regulatory Environment
Except for its investments in wind power and ROVA I, each of Power Operations' projects in the United States
is a QF under PURPA. See Item 3 and Note 18 of LG&E Energy's Notes to Financial Statements under Item 8 for a discussion of certain issues regarding past operations at certain of these facilities. Certain partnerships, in which companies in the Power Operations business segment have ownership interests, are operating wind power facilities which are qualifying small power production facilities under PURPA. In addition, Power Operations has obtained EWG status for the entities which own the ROVA I and ROVA II projects in North Carolina and the Southampton, Altavista and Hopewell projects in Virginia.
Generally, QF status exempts projects from the application of the Holding Company Act, many provisions of the FPA, and state laws and regulations respecting rates and financial or organization regulation of electric utilities. EWGs also are exempt from application of the Holding Company Act and many provisions of the FPA, but once such an entity files its electric generation rates with FERC, it becomes a jurisdictional public utility under the FPA. As a "public utility," an EWG's rates and some of its corporate activities are subject to FERC regulation. EWGs also are subject to non-rate regulation under state laws governing electric utilities. While QF or EWG status entitles Power Operations' projects to certain regulatory exceptions and benefits under PURPA and the Holding Company Act, each project must still comply with other federal, state and local laws, including those regarding siting, construction, operation, licensing and pollution abatement.
The foreign power generation facility in which Power Operations has an ownership interest has obtained FUCO status under the Holding Company Act. Generally, FUCO status exempts this facility from application of the Holding Company Act.
Commitments and Contingencies
Power Operations is party to various legal proceedings relating to its joint ventures. See Note 18 of LG&E Energy's Notes to Financial Statements under Item 8 for discussion regarding these legal proceedings.
WESTERN KENTUCKY ENERGY
General
In July 1998 the Company closed the transaction to lease the generating assets of Big Rivers. Under the 25-year operating lease, WKE operates the operating assets of Big Rivers' coal-fired facilities, a combustion turbine and operates and maintains the Station Two generating facility of Henderson. The combined generating capacity of these facilities is approximately 1,700 Mw, net of Henderson's capacity and energy needs from Station Two. Under the terms of the lease agreement, WKE prepaid $55.9 million for its first two years of lease payments and will pay $31.0 million for each of the remaining 23 years. In addition, WKE purchased Big Rivers' inventory, personal property and emission allowances, and made a one-time payment to Big Rivers of $12.1 million.
In related transactions, power is supplied to Big Rivers at contractual prices over the term of the lease to meet the needs of three member distribution cooperatives and their retail customers, including major western Kentucky aluminum smelters. The excess generating capacity is available to WKE to market throughout the region.
Also, as part of the transaction, in July 1998, WKE began advancing Big Rivers $50.0 million over a 24-month period to help it emerge from bankruptcy. The note will be repaid over a three-year period, beginning August 2000, with interest at 7.165%.
WKE's business is affected by seasonal weather patterns. As a result, operating revenues (and associated expenses) are not generated evenly throughout the year.
WKE is considering a merger of its three legal entities, Western Kentucky Energy Corp., WKE Station Two Inc. and WKE Corp. to consolidate these entities into the surviving entity of Western Kentucky Energy Corp. Should WKE complete the merger of these entities, WKE anticipates decertifying as an EWG.
Construction Program and Financing
In connection with these transactions, WKE has undertaken to bear certain of the future capital requirements of these generating assets. WKE's estimates of its construction expenditures can vary substantially due to numerous items beyond WKE's control, such as economic conditions, construction costs, and new environmental or other governmental laws and regulations. In 1999, gross property additions were $12.2 million. During 1998 gross property additions amounted to $11.8 million excluding personal property acquired from Big Rivers. Internally generated funds and intercompany financing from Capital Corp. provided 100% of the construction expenditures.
Coal Supply
Coal-fired generating units provided 90% of the electric generating capacity controlled by WKE, the remainder being made up of a combustion turbine peaking unit fueled by fuel oil. Coal is the predominant fuel used by WKE, with fuel oil being used for peaking capacity. WKE has entered into various multi-year coal supply agreements with suppliers for coal deliveries for 2000 and beyond. WKE normally augments its coal supply agreements with spot market purchases. At December 31, 1999, WKE had on hand coal inventory of approximately 1.5 million tons or a 75-day supply.
WKE expects, for the foreseeable future, to continue purchasing most of its coal, which has a sulfur content in the 2%-4.5% range, from western Kentucky and southwest Indiana. The abundant supply of this relatively low priced coal, combined with present and future desulfurization technologies, is expected to enable WKE to continue to provide adequate electric service in a manner acceptable under existing environmental laws and regulations.
Coal for WKE's operations are delivered by barge and truck.
The average delivered cost per ton of coal purchased by WKE for 1999 and 1998 respectively was $20.86 and $20.85.
Environmental Matters
WKE engages in a variety of activities within the jurisdiction of federal, state and local regulatory agencies. Those agencies have issued WKE permits for various activities subject to air quality, water quality and waste management laws and regulations. During 1999 and 1998, expenditures for pollution control facilities represented approximately $1.4 million and $.5 million of WKE's construction expenditures, respectively. See Note 18 of LG&E Energy's Notes to Financial Statements under Item 8 for a discussion of specific environmental proceedings.
ARGENTINE GAS DISTRIBUTION
General
In February 1997, the Company acquired interests in two Argentine natural gas distribution companies. Capital Corp., through a subsidiary, purchased a controlling interest in Centro and a minority interest in Cuyana. Centro and Cuyana together serve approximately 732,000 customers in six provinces in Argentina. The
investment in these companies totaled approximately $140 million. Each of these companies has obtained FUCO status under the Holding Company Act. Generally, FUCO status exempts these facilities from application of the Holding Company Act.
In April 1999, the Company acquired an interest in another Argentine natural gas distribution company. Capital Corp., through a subsidiary, purchased a minority interest in Gas BAN, the second largest gas distribution company in Argentina. Gas BAN serves approximately 1,188,000 customers in thirty counties in the northern region of Buenos Aires. The Company's investments in Gas BAN totaled $85.4 million through December 31, 1999.
Gas Operations
Centro's and Cuyana's primary source of gas supply is YPF, S.A., and its primary source of gas transmission is TGN, S.A. Centro and Cuyana have no underground storage facilities. Gas BAN's primary source of gas supply is YPF, S.A., and its primary sources of gas transmission are TGS, S.A. and TGN, S.A. Gas BAN has a shaving plant to cover peaking demand.
The Argentine federal regulator of gas transmission and distribution, Energas, has granted Centro, Cuyana and GasBAN 35-year concessions to provide gas distribution services in their service territories. The concessions end in 2028 and each concession contains a 10-year renewal option.
Centro derives approximately 12% of its revenues from electric power plants located in its service territory. Some of these power plants are state-owned. Centro sells gas to these plants under contracts ranging from two to 15 years.
Construction Program and Financing
Capital investments for Centro since 1992 have totaled approximately $284 million. Centro's capital expenditures for 1999 totaled $17 million and were financed through borrowing and internal sources. Centro will spend approximately $4.5 million in 2000 to expand and maintain its gas distribution network, and it will finance the expenditures through borrowings and internal sources.
CAPITAL CORP. OTHER
Gas Operations
As previously discussed in item 1 under Discontinuance of Merchant Energy Trading and Sales Business, effective June 30, 1998, the Company decided to discontinue its merchant energy trading and sales business, and it decided to sell its natural gas gathering and processing business. Effective June 30, 1999, the Company decided to retain the natural gas gathering and processing business. For a more detailed discussion of the discontinuance of the Company's merchant energy trading and sales business, and the decision to retain the natural gas gathering and processing business, see Discontinued Operations under this Item, and Notes 3, 4 and 18 of LG&E Energy's Notes to Financial Statements under Item 8.
Capital Corp.'s Gas Operations, conducted through various subsidiaries, include: gathering and processing operations consisting of 1,200 miles of pipeline concentrated in southeastern New Mexico and the Permian Basin of west Texas; and a 6.0 Bcf working gas storage facility connected to the Llano pipeline. For a more detailed explanation of these assets see Item 2, Properties.
The Llano pipeline has a design capacity of approximately 180,000 Mcf of gas per day and is capable of
delivering gas to three different interstate pipelines. Capital Corp., through its various subsidiaries, purchases gas from over 50 producers connected to the Llano pipeline and sells the gas directly to end-user customers or delivers the gas into one of the interstate pipelines for sale. Also, through its various subsidiaries, Capital Corp. transports natural gas through the Llano pipeline for third parties and is paid a transportation fee for such services. An average of approximately 100,000 Mcf of natural gas per day moved through the Llano pipeline in 1999.
The 11 gathering systems owned (seven 100%, one leased and ownership interests ranging from 11% to 50% in three others) and operated during 1999 gathered approximately 216,500 Mcf of natural gas per day. During 1999, Capital Corp. divested itself of its three partially owned gathering systems.
Connected to the Llano pipeline are two operating natural gas processing facilities capable of processing approximately 75,000 Mmbtu of natural gas per day. These facilities extract natural gas liquids, including propane, ethane, butanes and natural gasoline, from the natural gas stream, at which point the mixed stream of liquids is sold. Approximately 215,000 net gallons per day of natural gas liquids were extracted and sold from these facilities in 1999.
Also connected to the Llano pipeline is a natural gas storage facility. As noted above, this facility has current working capacity of approximately 6.0 Bcf. Capital Corp., through a subsidiary, offers this storage capacity to third parties on a fee basis. As of December 31, 1999, storage capacity of approximately 3.0 Bcf was leased to other parties.
The production, transportation and certain sales of natural gas are subject to federal, state or local regulations which have a significant impact upon Capital Corp.'s energy products and services businesses. Regulation at the federal level of domestically produced or transported natural gas is administered primarily by the FERC pursuant to the NGA and the NGPA. Maximum selling prices of certain categories of gas, whether sold in interstate or intrastate commerce, previously were regulated pursuant to NGPA. The NGPA established various categories of gas and provided for graduated deregulation of price controls of several categories of gas and the deregulation of sales of certain categories of gas. All price deregulation contemplated under the NGPA has already taken place. Subsequently, the Natural Gas Wellhead Decontrol Act of 1989 terminated all NGA and NGPA regulation of "first sales" of domestic natural gas on January 1, 1993. The sale for resale of certain natural gas in interstate commerce is regulated, in part, pursuant to the NGA, which requires certificate and abandonment authority to initiate and terminate such sales. In addition, natural gas marketed by a Capital Corp. subsidiary is usually transported by interstate pipeline companies that are subject to the jurisdiction of the FERC. Similarly, some of the transportation and storage services provided by Llano are subject to FERC regulation under section 311 of the NGPA. These services are frequently sold to gas distribution companies that contract with interstate pipeline companies for transportation from the Llano facility to their respective service areas. Section 311 permits intrastate pipelines under certain circumstances to sell gas to, transport gas for, or have gas transported by, interstate pipeline companies, and assign contract rights to purchase surplus gas from producers to interstate pipeline companies without being regulated as interstate pipelines under the NGA. Capital Corp., through a subsidiary, submitted a rate case for transportation and storage rates to the FERC in 1998 which was approved without intervention.
CRC - Evans
CRC provides specialized equipment and services used in the construction and rehabilitation of gas and oil transmission pipelines. CRC sells and rents automatic pipeline welding systems, pipe bending equipment, line-up clamps, pipe coating plants, coating and cleaning equipment, pipeline rehabilitation equipment and lay barge pipe handling equipment. CRC also provides specialized services including joint coating, cement weighting, induction and resistance heating and automatic welding systems training and supervision.
CRC sells its products and services through its salespeople and independent international sales representatives and distributors covering 70 countries. The company's sales offices are located in Houston, Texas; Tulsa, Oklahoma; Toms River, New Jersey; Hoevelaken, Netherlands; Edmonton, Alberta; Burnley, England and Didcot, England.
DISCONTINUED OPERATIONS
General
As previously discussed in item 1 under Discontinuance of Merchant Energy Trading and Sales Business, effective June 30, 1998, the Company decided to discontinue its merchant energy trading and sales business, and it decided to sell its natural gas gathering and processing business. Effective June 30, 1999, the Company decided to retain the natural gas gathering and processing business. For a more detailed discussion of the discontinuance of the Company's merchant energy trading and sales business, and the decision to retain the natural gas gathering and processing business, see Discontinued Operations under this Item, and Notes 3, 4 and 18 of LG&E Energy's Notes to Financial Statements under Item 8. In December 1999, LEM, the entity primarily conducting the discontinued operations activities and formerly an indirect subsidiary of Capital Corp., became a direct subsidiary of LG&E Energy.
Product and Services
The merchant energy trading and sales business consisted primarily of a portfolio of energy marketing contracts entered into in 1996 and 1997, nationwide deal origination and some level of speculative trading activities, which were not directly supported by the Company's physical assets.
Commitments and Contingencies
For discussions of commitments and contingencies relating to Discontinued Operations, see Note 18 of LG&E Energy 's Notes to Financial Statements under Item 8.
EMPLOYEES AND LABOR RELATIONS
LG&E Energy and its subsidiaries had 5,836 full-time employees at December 31, 1999, including 2,237 full-time employees of LG&E and 1,747 full-time employees of KU. At December 31, 1999, LG&E had 1,297 operating, maintenance, and construction employees that were members of IBEW Local 2100. The current three year contract with the IBEW will expire in November 2001. At December 31, 1999, KU had 239 operating, maintenance and construction employees who were members of IBEW Local 101 and USWA Local 8686. The current contract will expire August 1, 2000. At December 31, 1999, WKE had 358 operating, maintenance and construction employees that were members of the IBEW Local 1701. The current contract will expire September 14, 2001.
ITEM 2.
ITEM 2. Properties.
LG&E's power generating system consists of the coal-fired units operated at its three steam generating stations. Combustion turbines supplement the system during peak or emergency periods. LG&E owns and operates the following electric generating stations:
Capability Rating (Kw) -----------
Steam Stations: Mill Creek - Kosmosdale, KY. Unit 1 303,000 Unit 2 301,000 Unit 3 386,000 Unit 4 480,000 --------- Total Mill Creek 1,470,000
Cane Run - near Louisville, KY. Unit 4 155,000 Unit 5 168,000 Unit 6 240,000 --------- Total Cane Run 563,000
Trimble County - Bedford, KY. (a) Unit 1 371,000
Combustion Turbine Generators (Peaking capability): Zorn 16,000 Paddy's Run 43,000 Cane Run 16,000 Waterside 33,000 E.W.Brown (b) 125,000 --------- Total combustion turbine generators 233,000 ---------
Total capability rating 2,637,000 =========
(a) Amount shown represents LG&E's 75% interest in Trimble County. See Note 13 of LG&E's Notes to Financial Statements and Note 19 of LG&E Energy's Notes to Financial Statements, Jointly Owned Electric Utility Plant, under Item 8 for further discussion on ownership.
(b) Amount shown represents LG&E's 38% interest in Unit 6 and 7 at E.W. Brown. See Notes 12 and 13 of LG&E's Notes to Financial Statements, and Notes 18 and 19 of LG&E Energy's Notes to Financial Statements under Item 8 for further discussion on ownership.
LG&E also owns an 80 Mw hydroelectric generating station located in Louisville, operated under license issued by the FERC.
At December 31, 1999, LG&E's electric transmission system included 21 substations with a total capacity of approximately 11,071,700 Kva and approximately 652 structure miles of lines. The electric distribution system included 84 substations with a total capacity of approximately 3,448,730 Kva, 3,672 structure miles of overhead lines, 342 miles of underground conduit, and 5,562 miles of underground conductors.
LG&E's gas transmission system includes 209 miles of transmission mains, and the gas distribution system includes 3,789 miles of distribution mains.
LG&E operates underground gas storage facilities with a current working gas capacity of approximately 14.6 million Mcf. See Gas Supply under Item 1.
In 1990, LG&E entered into an operating lease for its corporate office building located in downtown Louisville, Kentucky. The lease is for a period of 15 years and is scheduled to expire June 2005.
Other properties owned by LG&E include office buildings, service centers, warehouses, garages, and other structures and equipment, the use of which is common to both the electric and gas departments.
The trust indenture securing LG&E's First Mortgage Bonds constitutes a direct first mortgage lien upon much of the property owned by LG&E.
KU's power generating system consists of the coal-fired units operated at its five steam generating stations. Combustion turbines supplement the system during peak or emergency periods. KU owns and operates the following electric generating stations:
Capability Rating (Kw) -----------
Steam Stations: Tyrone - Tyrone, KY. Unit 1 30,000 Unit 2 33,000 Unit 3 73,000 ----------- Total Tyrone 136,000
Green River - South Carrollton, KY. Unit 1 29,000 Unit 2 30,000 Unit 3 73,000 Unit 4 107,000 ----------- Total Green River 239,000
E.W. Brown - Burgin, KY. Unit 1 106,000 Unit 2 170,000 Unit 3 441,000 ----------- Total E.W. Brown 717,000
Pineville - Four Mile, KY. Unit 3 34,000
Ghent - Ghent, KY. Unit 1 487,000 Unit 2 497,000 Unit 3 513,000 Unit 4 500,000 ----------- Total Ghent 1,997,000
Combustion Turbine Generators (Peaking capability): E.W. Brown - Burgin, KY. Unit 6 (a) 102,000 Unit 7 (a) 102,000 Unit 8 135,000 Unit 9 120,000 Unit 10 135,000 Unit 11 122,000 Haefling - Lexington, KY. Unit 1 59,000 -----------
Total combustion turbine generators 775,000 -----------
Total capability rating 3,898,000 ===========
(a) Amount shown represents the KU's 62% interest in Unit 6 and 7 at E.W. Brown. See Notes 11and 12 of KU's Notes to Financial Statements, and Notes 18 and 19 of LG&E Energy's Notes to Financial Statements under Item 8 for further discussion on ownership.
Substantially all properties are subject to the lien of KU's Mortgage Indenture.
KU also owns a 24 Mw hydroelectric generating station located in Burgin, Kentucky, operated under license issued by the FERC.
At December 31, 1999, KU's electric transmission system included 112 substations with a total capacity of approximately 14,755,396 Kva and approximately 4,227 structure miles of lines. The electric distribution system included 438 substations with a total capacity of approximately 5,024,307 Kva, 14,619 structure miles of lines.
At December 31, 1999, Power Operations owned the percentage indicated of the following joint ventures:
Net Ownership Capability Name Interest % Fuel Rating (Mw) ---- --------- ---- -----------
LG&E Westmoreland-Southampton 50 Coal 63 Franklin, Virginia
LG&E Westmoreland-Altavista 50 Coal 63 Altavista, Virginia
LG&E Westmoreland-Hopewell 50 Coal 63 Hopewell, Virginia
Westmoreland-LG&E Partners 50 Coal 165 (Roanoke Valley I) Weldon, North Carolina
Windpower Partners 1993 L.P. 50 Wind 43 Palm Springs, California
Windpower Partners 1993 L.P. 50 Wind 25 Buffalo Ridge, Minnesota
Windpower Partners 1994 L.P. 25 Wind 25-35 Culberson County, Texas
Westmoreland-LG&E Partners 50 Coal 44 (Roanoke Valley II) Weldon, North Carolina
K.W. Tarifa, S.A. 46 Wind 30 Tarifa, Spain
Tenaska Limited Partnerships 5-10 Gas 223-258
Gregory Power Partners 50 Gas 550 Gregory, Texas (under construction)
Power Operations' ownership interests in these projects and the revenues from the sale of electricity and steam from the projects are pledged as security to the lenders who provided the financing for the project. See Note 18 of LG&E Energy's Notes to Financial Statements under Item 8 for a discussion Power Operations' commitment and contingencies relating to its joint ventures. Also see Note 9 of LG&E Energy's Notes to Financial
Statements under Item 8 for a discussion on investment in unconsolidated ventures.
In March 1999, LG&E-Westmoreland Rensselaer, a California general partnership in which the Company owns a 50% interest, sold substantially all the assets and major contracts of its 79 Mw gas-fired cogeneration facility in Rensselaer, New York, with net proceeds to the Company of approximately $34 million. The sale resulted in an after-tax gain to the Company of approximately $8.9 million.
Capital Corp., through certain subsidiaries, owns or has an interest in eight gas gathering systems consisting of 1,200 miles of pipeline (of which it owns 100% of four, leases one, and has ownership interests ranging from 11% to 50% in the other three). These systems are located in Texas, New Mexico, Louisiana, Montana and Oklahoma.
The major gas gathering system is the Llano pipeline, a 730-mile intrastate pipeline and processing system in southeastern New Mexico with a throughput capacity of 180,000 MCF of gas per day. Capital Corp., through subsidiaries, owns two gas systems located in Texas. PowerTex Pipeline, a 76-mile pipeline serving the City of Lubbock, Texas, has a design capacity of 90,000 MCF of gas per day. The Sale Ranch system consists of a 16mmcfd processing plant and approximately 350 miles of gathering pipelines. Through a subsidiary, Capital Corp. owns majority interest and operates the Sale Ranch system. It also owns, or has interests in, and operates three natural gas processing plants located in southeastern New Mexico and western Texas with a total design capacity of 92,000 MCF of gas per day (owns a 100% interest in one of these plants, and majority interests in the two remaining plants).
Under a 25-year operating lease, WKE operates Big Rivers' coal-fired facilities, a combustion turbine and operates and maintains the Station Two generating facility of Henderson. The combined generating capacity of these facilities is approximately 1,700 Mw, net of Henderson's capacity and energy needs from Station Two.
Centro's gas transmission and distribution system includes 6,646 miles of transmission mains and distribution mains located in Cordoba, Argentina, and neighboring provinces. Cuyana's gas transmission and distribution system includes approximately 4,899 miles of transmission mains and distribution mains located in Mendoza Province, Argentina, and neighboring provinces. Gas BAN's transmission and distribution system includes 11,580 miles of transmission and distribution mains in the northern region of Buenos Aires.
CRC owns a 29-acre equipment yard/manufacturing/maintenance facility and supply warehouse in Tulsa, Oklahoma and a 9,800 square foot sales office/warehouse/service facility in Edmonton, Canada. The company leases all other facilities used in its operations, including its corporate offices in Houston, Texas and various office facilities and equipment sites in the United States, United Kingdom and the Netherlands.
LG&E Energy has operating leases for its corporate office space that expire between 2000 and 2012.
ITEM 3.
ITEM 3. Legal Proceedings.
Rates and Regulatory Matters
For a discussion of current regulatory matters, including, among others, a discussion of (a) rate matters related to the Kentucky Commission's proceeding involving the Company's PBR filings and the KIUC's rate filing, (b) proceedings before the Kentucky Supreme Court and the Kentucky Commission regarding environmental cost recovery surcharge refunds, and (c) fuel adjustment clause proceedings before the Kentucky Commission regarding electric line loss refunds, see Rates and Regulation under Item 7 and Notes 2, 6, 18 and 22 of LG&E Energy Corp.'s Notes to Financial Statements, Notes 3, 12 and 16 of LG&E's Notes to Financial Statements and Notes 3, 11 and 14 of KU's Notes to Financial Statements under Item 8.
Performance-Based Ratemaking
In October, 1998, LG&E and KU filed applications with the Kentucky Commission for approval of the PBR proposal for determining electric rates. In January 2000, the Kentucky Commission issued orders requiring LG&E and KU to reduce annual base rates by $27.2 and $36.5, respectively, effective March 1, 2000. The orders also eliminated the temporary effectiveness of the PBR proposal, reinstated the FAC mechanism and offered the utilities a three year ESM program whereby incremental annual earnings above or below a range of 10.5% to 12.5% would be shared 60% with shareholders and 40% with ratepayers. In January and February 2000, LG&E and KU submitted filings seeking adjustments in the rate reductions and tariffs incorporating the ESM. See Rates and Regulations under Item 7 and Notes 6 and 22 to LG&E Energy's Notes to Financial Statements, Notes 3 and 16 to LG&E's Notes to Financial Statements and Notes 3 and 14 to KU's Notes to Financial Statements.
Fuel Adjustment Clause Proceedings
Pursuant to Kentucky statute, aspects of the Company's utility rates are reviewed through semi-annual FAC proceedings at the Kentucky Commission. Although the proceedings are routine, some items are noted herein. Certain intervenors have challenged KU's recovery of certain energy charges for power purchased from Owensboro Municipal Utilities and requested rate refunds for such amounts. Kentucky Commission orders of August 1999 and January 2000 have required aggregate refunds totaling approximately $8.4 million for the periods between November 1996 to October 1999. These orders have been appealed by both KU and the intervenor group. See also Note 6 to LG&E Energy's Notes to Financial Statements, Note 3 to LG&E's Notes to Financial Statements and Note 3 to KU's Notes to Financial Statements. See Rates and Regulatory Matters above regarding further matters arising during LG&E's and KU's FAC proceedings.
Environmental
For a discussion of environmental matters concerning (a) currently proposed reductions in NOx and SO2 emission limits, (b) issues at LG&E's Mill Creek and Cane Run generating plants and LG&E's and KU's manufactured gas plant sites, and (c) other environmental items affecting LG&E Energy and its subsidiaries, see Environmental Matters under Item 7 and Notes 18 and 22 of LG&E Energy's Notes to Financial Statements, Notes 12 and 16 of LG&E's Notes to Financial Statements and Notes 11 and 14 of KU's Notes to Financial Statements under Item 8, respectively.
Southampton
For a discussion of the settlement of certain FERC proceedings and intra-party matters involving the partnership that owns the Southampton facility, regarding that facility's status as a qualifying facility for 1992, see Note 18 of LG&E Energy Corp.'s Notes to Financial Statements under Item 8.
Roanoke Valley I
WLP is seeking the recovery of capacity payments withheld by VEPCO in respect of the Roanoke Valley I facility. In January 2000, the Virginia Supreme Court issued an opinion remanding this matter for a second trial, setting aside an earlier trial court decision which had awarded WLP approximately $19 million plus interest until paid. See Item 1 and Notes 18 and 22 of LG&E Energy Corp.'s Notes to Financial Statements under Item 8.
Kenetech Bankruptcy
In May 1996, Kenetech filed for protection under Chapter 11 of the United States Bankruptcy Code in the
United States Bankruptcy Court in the Northern District of California seeking, among other things, to restructure certain contractual commitments between Kenetech and its subsidiaries, on one hand, and various windpower projects located in the U.S. and abroad, on the other hand. Included in these projects are the WPP 93, WPP 94 and Tarifa projects. In April 1999, the Bankruptcy Court approved a final plan of reorganization. See Note 18 of LG&E Energy Corp.'s Notes to Financial Statements under Item 8 for a further discussion.
Windpower Partners 1994
WPP 94, in which the Company has a 25% interest through indirect subsidiaries, has not made semiannual payments, since September 1997, to Hancock under certain Notes issued by WPP 94 to Hancock. The parties are currently in negotiations regarding a restructuring of these obligations. See Note 18 of LG&E Energy Corp.'s Notes to Financial Statements under Item 8 for a further discussion.
Calgary
In November 1996, LG&E Natural Canada Inc., an indirect subsidiary of the Company, initiated action in the Court of the Queens Bench of Alberta, Calgary against a former employee as a result of the discovery that the former employee had engaged in unauthorized transactions. See Note 18 to LG&E Energy's Notes to Financial Statements, under Item 8 for a further discussion.
Springfield Municipal Contract
In July 1998, LEM, an indirect subsidiary of the Company, filed suit against the CWLP in the United States District Court for the Western District of Kentucky. In January 2000, LEM reached a settlement with CWLP pursuant to which CWLP paid LEM approximately $16.6 million. See Note 18 to LG&E Energy's Notes to Financial Statements under Item 8 for a further discussion.
Oglethorpe Power Contract
In October 1998, LEM initiated an arbitration proceeding against OPC in connection with matters involving LEM's November 1996 power sales agreement with OPC. In December 1999, the arbitration panel issued an adverse decision in this proceeding enforcing the contract without modification. In connection therewith, the Company increased its after-tax loss on disposal of discontinued operations by $175 million. See Note 3 to LG&E Energy's Notes to Financial Statements under Item 8 for a further discussion.
Other
In the normal course of business, other lawsuits, claims, environmental actions, and other governmental proceedings arise against LG&E Energy and its subsidiaries, including LG&E and KU. To the extent that damages are assessed in any of these lawsuits, LG&E Energy, LG&E and KU believe that their insurance coverage is adequate. Management, after consultation with legal counsel, does not anticipate that liabilities arising out of other currently pending or threatened lawsuits and claims will have a material adverse effect on LG&E's Energy's, LG&E's or KU's consolidated financial position or results of operations, respectively.
ITEM 4.
ITEM 4. Submission of Matters to a Vote of Security Holders.
None.
Executive Officers of LG&E Energy Corp.:
Effective Date of Election to Present Name Age Position Position - ---- --- -------- --------
Roger W. Hale 56 Chairman of the Board August 17, 1990 and Chief Executive Officer
Victor A. Staffieri 44 President and Chief February 16, 1999 Operating Officer
R. Foster Duncan 46 Executive Vice President February 16, 1999 and Chief Financial Officer
Stephen R. Wood 57 Group Executive - January 1, 2000 Retail Business
Robert M. Hewett 53 Group Executive - January 1, 2000 Regulatory Affairs
John R. McCall 56 Executive Vice President, July 1, 1994 General Counsel and Corporate Secretary
Wayne T. Lucas 52 Executive Vice President - May 4, 1998 Power Generation
George W. Basinger 54 Senior Vice President - May 4, 1998 Independent Power Operations
Donald F. Santa, Jr. 41 Senior Vice President - January 1, 2000 Strategic Planning
Frederick J. Newton III 44 Senior Vice President and January 2, 1999 Chief Administrative Officer
S. Bradford Rives 41 Senior Vice President - February 16, 1999 Finance and Business Development
Paul W. Thompson 43 Senior Vice President - August 9, 1999 Energy Services
Rebecca L. Farrar 40 Senior Vice President - January 1, 2000 Distribution Operations
Wendy C. Heck 46 Vice President - Infor- February 3, 1998 mation Technology
Chris Hermann 52 Vice President, Supply January 1, 2000 and Logistics
Effective Date of Election to Present Name Age Position Position - ---- --- -------- --------
Charles A. Markel 52 Vice President - January 1, 1993 Finance and Treasurer
Michael D. Robinson 44 Vice President and February 16, 1999 Controller
The present term of office of each of the above executive officers extends to the meeting of the Board of Directors following the Annual Meeting of Shareholders, scheduled to be held in June 2000.
There are no family relationships between executive officers of the Company or executive officers of its subsidiaries.
Messrs. Hale, Lucas, Duncan, Wood, Hewett, McCall, Newton, Markel and Robinson, and Ms. Farrar and Ms. Heck are also executive officers of LG&E and KU. Mr. Hale is Chairman of the Board and Chief Executive Officer of LG&E and KU; Mr. Lucas is Executive Vice President - Power Generation of LG&E and KU; Mr. Duncan is Chief Financial Officer of LG&E and KU; Mr. Wood is Group Executive - Retail Business of LG&E and KU; Mr. Hewett is Group Executive - Regulatory Affairs of LG&E and KU; Mr. McCall is Executive Vice President, General Counsel and Corporate Secretary of LG&E and KU; Mr. Newton is Senior Vice President and Chief Administrative Officer of LG&E and KU; Mr. Markel is Treasurer of LG&E and KU; Mr. Robinson is Vice President and Controller of LG&E and KU; Ms. Farrar is Senior Vice President - Distribution Operations of LG&E and KU; and Ms. Heck is Vice President - Information Technology of LG&E and KU. Mr. Hermann is also Vice President, Supply and Logistics of LG&E.
Mr. Hale was President of LG&E Energy from December 1992 to May 1998.
Before he was elected to his current position, Mr. Staffieri was President of LG&E from January 1994 to May 1997; President - Distribution Services of LG&E Energy Corp. from December 1995 to May 1997; Chief Financial Officer of LG&E Energy Corp. and LG&E from May 1997 to February 1999; and Chief Financial Officer of KU from May 1998 to February 1999.
Before he was elected to his current position, Mr. Duncan was Vice President and Corporate Treasurer of Freeport-McMoRan, Inc. and Freeport-McMoRan Copper & Gold Inc. and their affiliates from May 1994 to January 1998; and Executive Vice President - Planning and Development of LG&E Energy Corp. from January 1998 to February 1999.
Before he was elected to his current position, Mr. Wood was Executive Vice President and Chief Administrative Officer of LG&E Energy Corp. from January 1994 to May 1997 and President - Distribution Services Division and President - Louisville Gas and Electric Company from May 1997 to December 1999.
Before he was elected to his current position, Mr. Hewett was Vice President - Regulation and Economic Planning of KU from January 1982 to April 1997; Senior Vice President - Customer Service and Marketing of KU from April 1997 to May 1998; and President of KU from May 1998 to December 1999.
Before he was elected to his current position, Mr. Lucas was Vice President, Energy Supply of KU from November 1986 to November 1994; and Senior Vice President, Energy Supply of KU from November 1994 to May 1998.
Before he was elected to his current position, Mr. Basinger was Senior Vice President of Operations of LG&E Power Inc. from November 1994 to August 1996; and Senior Vice President - Power Operations of LG&E Energy Corp. from August 1996 to May 1998.
Before he was elected to his current position, Mr. Santa was a member of the Federal Energy Regulatory Commission from May 1993 to August 1997; and Vice President and Deputy General Counsel of LG&E Energy Corp. from September 1997 to October 1998; and Senior Vice President and Deputy General Counsel of LG&E Energy Corp. from October 1998 to December 1999.
Before he was elected to his current position, Mr. Newton was Director of Human Resources, Manufacturing and Engineering at Unilever from October 1993 to July 1995; Senior Director, Human Resources, Supply Chain, at Unilever from August 1995 to July 1996; Vice President, Human Resources, at Venator Group from August 1996 to July 1997; Senior Vice President, Human Resources, at Venator Group's Champs Sports Division from August 1997 to April 1998; and Senior Vice President - - Human Resources and Administration of LG&E Energy Corp., LG&E and KU from May 1998 to January 1999.
Before he was elected to his current position, Mr. Rives was Vice President and Treasurer of LG&E Power Inc. from June 1994 to March 1995; Vice President, Controller and Treasurer of LG&E Power Inc. from March 1995 to December 1995; Vice President - Finance, Non-Utility Business of LG&E Energy Corp. from January 1996 to March 1996; and Vice President - Finance and Controller of LG&E Energy Corp. from March 1996 to February 1999.
Before he was elected to his current position, Mr. Thompson was Vice President-Business Development for LG&E Energy Corp. from July 1994 to September 1996; Vice President, Retail Electric Business for LG&E from September 1996 to June 1998; Group Vice President for LG&E Energy Marketing, Inc., from June 1998 to August 1999; and Vice President, Retail Electric Business for LG&E from December 1998 to August 1999.
Before she was elected to her current position, Ms. Farrar was General Manager, Gas Operations of South Carolina Electric and Gas Company from July 1994 to February 1995 and Vice President - Gas Service Business of LG&E from February 1995 to December 1999.
Before she was elected to her current position, Ms. Heck was Vice President - Information Services of LG&E from January 1994 to May 1997; and Vice President, Administration, of LG&E Energy Corp. from May 1997 to February 1998.
Before he was elected to his current position, Mr. Hermann was Vice President and General Manager, Wholesale Electric Business of LG&E from January 1993 to June 1997; Vice President, Business Integration of LG&E from June 1997 to May 1998; and Vice President, Power Generation and Engineering Services, of LG&E from May 1998 to December 1999.
Before he was elected to his current position, Mr. Robinson was Controller of KU Energy Corporation from June 1990 to May 1998; Controller of KU from August 1990 to May 1998, and Vice President and Controller of LG&E and KU from May 1998 to the present.
Executive Officers of LG&E:
Effective Date of Election to Present Name Age Position Position - ---- --- -------- --------
Roger W. Hale 56 Chairman of the Board, January 1, 1992 and Chief Executive Officer
Stephen R. Wood 57 Group Executive - January 1, 2000 Retail Business
Robert M. Hewett 53 Group Executive - January 1, 2000 Regulatory Affairs
R. Foster Duncan 46 Executive Vice President February 16, 1999 and Chief Financial Officer
John R. McCall 56 Executive Vice President, July 1, 1994 General Counsel and Corporate Secretary
Wayne T. Lucas 52 Executive Vice President - May 4, 1998 Power Generation
Frederick J. Newton III 44 Senior Vice President and January 2, 1999 Chief Administrative Officer
Rebecca L. Farrar 40 Senior Vice President - January 1, 2000 Distribution Operations
Wendy C. Heck 46 Vice President - Infor- February 3, 1998 mation Technology
Chris Hermann 52 Vice President, Supply January 1, 2000 and Logistics
Michael D. Robinson 44 Vice President and May 4, 1998 Controller
Charles A. Markel 52 Treasurer January 1, 1993
The present term of office of each of the above executive officers extends to the meeting of the Board of Directors following the Annual Meeting of Shareholders, scheduled to be held in June 2000.
There are no family relationships between executive officers of LG&E.
Messrs. Hale, Lucas, Duncan, Wood, Hewett, McCall, Newton, Markel and Robinson, and Ms. Farrar and Ms. Heck are also executive officers of LG&E Energy Corp. and KU. Mr. Hale is Chairman of the Board and Chief Executive Officer of LG&E Energy Corp. and KU; Mr. Lucas is Executive Vice President - Power Generation of LG&E Energy Corp. and KU; Mr. Duncan is Chief Financial Officer of LG&E Energy Corp. and KU; Mr. Wood is Group Executive - Retail Business of LG&E Energy Corp. and KU; Mr. Hewett is Group Executive -
Regulatory Affairs of LG&E Energy Corp. and KU; Mr. McCall is Executive Vice President, General Counsel and Corporate Secretary of LG&E Energy Corp. and KU; Mr. Newton is Senior Vice President and Chief Administrative Officer of LG&E Energy Corp. and KU; Mr. Markel is Vice President - Finance and Treasurer of LG&E Energy Corp. and Treasurer of KU; Mr. Robinson is Vice President and Controller of LG&E Energy Corp. and KU; Ms. Farrar is Senior Vice President - Distribution Operations of LG&E Energy Corp. and KU; and Ms. Heck is Vice President - Information Technology of LG&E Energy Corp and KU. Mr. Hermann is also Vice President, Supply and Logistics of LG&E Energy Corp.
Before he was elected to his current position, Mr. Wood was Executive Vice President and Chief Administrative Officer of LG&E Energy Corp. from January 1994 to May 1997 and President - Distribution Services Division and President - Louisville Gas and Electric Company from May 1997 to December 1999.
Before he was elected to his current position, Mr. Hewett was Vice President - Regulation and Economic Planning of KU from January 1982 to April 1997; Senior Vice President - Customer Service and Marketing of KU from April 1997 to May 1998; and President of KU from May 1998 to December 1999.
Before he was elected to his current position, Mr. Duncan was Vice President and Corporate Treasurer of Freeport-McMoRan, Inc. and Freeport-McMoRan Copper & Gold Inc. and their affiliates from May 1994 to January 1998; and Executive Vice President - Planning and Development of LG&E Energy Corp. from January 1998 to February 1999.
Before he was elected to his current position, Mr. Lucas was Vice President, Energy Supply of KU from November 1986 to November 1994; and Senior Vice President, Energy Supply of KU from November 1994 to May 1998.
Before he was elected to his current position, Mr. Newton was Director of Human Resources, Manufacturing and Engineering at Unilever from October 1993 to July 1995; Senior Director, Human Resources, Supply Chain, at Unilever from August 1995 to July 1996; Vice President, Human Resources, at Venator Group from August 1996 to July 1997; Senior Vice President, Human Resources, at Venator Group's Champs Sports Division from August 1997 to April 1998; and Senior Vice President - - Human Resources and Administration of LG&E Energy Corp., LG&E and KU from May 1998 to January 1999.
Before she was elected to her current position, Ms. Farrar was General Manager, Gas Operations of South Carolina Electric and Gas Company from July 1994 to February 1995 and Vice President - Gas Service Business of LG&E from February 1995 to December 1999.
Before she was elected to her current position, Ms. Heck was Vice President - Information Services of LG&E from January 1994 to May 1997; and Vice President, Administration of LG&E Energy Corp. from May 1997 to February 1998.
Before he was elected to his current position, Mr. Hermann was Vice President and General Manager, Wholesale Electric Business of LG&E from January 1993 to June 1997; Vice President, Business Integration of LG&E from June 1997 to May 1998; and Vice President, Power Generation and Engineering Services, of LG&E from May 1998 to December 1999.
Before he was elected to his current position, Mr. Robinson was Controller of KU Energy Corporation from June 1990 to May 1998; and Controller of KU from August 1990 to May 1998.
Executive Officers of KU:
Effective Date of Election to Present Name Age Position Position - ---- --- -------- --------
Roger W. Hale 56 Chairman of the Board, May 4, 1998 and Chief Executive Officer
Stephen R. Wood 57 Group Executive - January 1, 2000 Retail Business
Robert M. Hewett 53 Group Executive - January 1, 2000 Regulatory Affairs
Wayne T. Lucas 52 Executive Vice President - May 4, 1998 Power Generation
R. Foster Duncan 46 Executive Vice President February 16, 1999 and Chief Financial Officer
John R. McCall 56 Executive Vice President, May 4, 1998 General Counsel and Corporate Secretary
Frederick J. Newton III 44 Senior Vice President and January 2, 1999 Chief Administrative Officer
Rebecca L. Farrar 40 Senior Vice President - January 1, 2000 Distribution Operations
Wendy C. Heck 46 Vice President - Infor- April 21, 1999 mation Technology
Gary E. Blake 46 Vice President - Sales May 4, 1998 and Service
James J. Ellington 54 Vice President - Power May 4, 1998 Generation
Michael D. Robinson 44 Vice President and May 4, 1998 Controller
Charles A. Markel 52 Treasurer May 4, 1998
The present term of office of each of the above executive officers extends to the meeting of the Board of Directors following the Annual Meeting of Shareholders, scheduled to be held in June 2000.
There are no family relationships between executive officers of KU.
Messrs. Hale, Lucas, Duncan, Wood, Hewett, McCall, Newton, Markel and Robinson, and Ms. Farrar and Ms. Heck are also executive officers of LG&E Energy Corp. and LG&E. Mr. Hale is Chairman of the Board and
Chief Executive Officer of LG&E Energy Corp. and LG&E; Mr. Lucas is Executive Vice President - Power Generation of LG&E Energy Corp. and LG&E; Mr. Duncan is Chief Financial Officer of LG&E Energy Corp. and LG&E; Mr. Wood is Group Executive - Retail Business of LG&E Energy Corp. and LG&E; Mr. Hewett is Group Executive - Regulatory Affairs of LG&E Energy Corp. and LG&E; Mr. McCall is Executive Vice President, General Counsel and Corporate Secretary of LG&E Energy Corp. and LG&E; Mr. Newton is Senior Vice President and Chief Administrative Officer of LG&E Energy Corp. and LG&E; Mr. Markel is Vice President - Finance and Treasurer of LG&E Energy Corp. and Treasurer of LG&E; Mr. Robinson is Vice President and Controller of LG&E Energy Corp. and LG&E; Ms. Farrar is Senior Vice President - Distribution Operations of LG&E Energy Corp. and KU; and Ms. Heck is Vice President - Information Technology of LG&E Energy Corp. and KU.
Before he was elected to his current position, Mr. Hale was Chairman of the Board and Chief Executive Officer of LG&E Energy Corp. from August 1990 to the present and Chairman of the Board and Chief Executive Officer of LG&E from January 1992 to the present.
Before he was elected to his current position, Mr. Wood was Executive Vice President and Chief Administrative Officer of LG&E Energy Corp. from January 1994 to May 1997 and President - Distribution Services Division and President - Louisville Gas and Electric Company from May 1997 to December 1999.
Before he was elected to his current position, Mr. Hewett was Vice President - Regulation and Economic Planning of KU from January 1982 to April 1997; Senior Vice President - Customer Service and Marketing of KU from April 1997 to May 1998; and President of KU from May 1998 to December 1999.
Before he was elected to his current position, Mr. Lucas was Vice President, Energy Supply of KU from November 1986 to November 1994; and Senior Vice President, Energy Supply of KU from November 1994 to May 1998.
Before he was elected to his current position, Mr. Duncan was Vice President and Corporate Treasurer of Freeport-McMoRan, Inc. and Freeport-McMoRan Copper & Gold Inc. and their affiliates from May 1994 to January 1998; and Executive Vice President - Planning and Development of LG&E Energy Corp. from January 1998 to February 1999.
Before he was elected to his current position, Mr. McCall was Executive Vice President, General Counsel and Corporate Secretary of LG&E Energy Corp. and LG&E from July 1994 to the present.
Before he was elected to his current position, Mr. Newton was Director of Human Resources, Manufacturing and Engineering at Unilever from October 1993 to July 1995; Senior Director, Human Resources, Supply Chain, at Unilever from August 1995 to July 1996; Vice President, Human Resources, at Venator Group from August 1996 to July 1997; Senior Vice President, Human Resources, at Venator Group's Champs Sports Division from August 1997 to April 1998; and Senior Vice President - - Human Resources and Administration of LG&E Energy Corp., LG&E and KU from May 1998 to January 1999.
Before she was elected to her current position, Ms. Farrar was General Manager, Gas Operations of South Carolina Electric and Gas Company from July 1994 to February 1995 and Vice President - Gas Service Business of LG&E from February 1995 to December 1999.
Before she was elected to her current position, Ms. Heck was Vice President - Information Services of LG&E from January 1994 to May 1997; and Vice President, Administration of LG&E Energy Corp. from May 1997 to February 1998; and Vice President - Information Technology of LG&E Energy Corp. and LG&E from February 1998 to the present.
Before he was elected to his current position, Mr. Blake was Vice President - Retail Marketing of KU from November 1992 to May 1998.
Before he was elected to his current position, Mr. Ellington was Superintendent of KU's Ghent plant from May 1986 to May 1998.
Before he was elected to his current position, Mr. Robinson was Controller of KU Energy Corporation from June 1990 to May 1998 and Controller of KU from August 1990 to May 1998.
Before he was elected to his current position, Mr. Markel was Vice President - Finance and Treasurer of LG&E Energy Corp. and Treasurer of LG&E from January 1993 to the present.
PART II.
ITEM 5.
ITEM 5. Market for the Registrant's Common Equity and Related Stockholder Matters.
LG&E Energy:
LG&E Energy 's Common Stock is listed on the New York and Chicago Stock Exchanges. The ticker symbol is "LGE." The newspaper stock exchange listings are "LGE Energy" or "LGE EN." The following table gives information with respect to price ranges, as reported via the "GPC" screen by the Bloomberg L.P. Information Service as New York Stock Exchange Composite Transactions, and dividends paid for the periods shown (dividends paid have not been restated to reflect the KU merger).
The number of record holders of Common Stock at December 31, 1999, totaled 48,296. The book value of the Company's Common Stock at December 31, 1999, was $8.80 per share.
LG&E:
All LG&E common stock, 21,294,223 shares, is held by LG&E Energy. Therefore, there is no public market for LG&E's common stock.
The following table sets forth LG&E's cash distributions on common stock paid to LG&E Energy (in thousands of $):
1999 1998 ---- ----
First quarter $22,000 $20,000 Second quarter 22,000 19,800 Third quarter 22,000 21,200 Fourth quarter 23,000 22,000
KU:
All KU common stock, 37,817,878 shares, is held by LG&E Energy. Therefore, there is no public market for KU's common stock.
The following table sets forth KU's cash distributions on common stock paid (in thousands of $):
1999 1998 ---- ----
First quarter $18,000 $17,018 Second quarter 18,000 5,673 Third quarter 18,000 17,400 Fourth quarter 19,000 18,000
ITEM 6.
ITEM 6. Selected Financial Data.
Years Ended December 31 (Thousands of $ Except per Share Data)
Years Ended December 31 (Thousands of $ Except per Share Data)
LG&E Energy's Management's Discussion and Analysis of Results of Operations and Financial Condition and the Notes to Financial Statements should be read in conjunction with the above information.
Years Ended December 31 (Thousands of $)
LG&E's Management's Discussion and Analysis of Results of Operations and Financial Condition and LG&E's Notes to Financial Statements should be read in conjunction with the above information.
Years Ended December 31 (Thousands of $)
Years Ended December 31 (Thousands of $)
KU's Management's Discussion and Analysis of Results of Operations and Financial Condition and KU's Notes to Financial Statements should be read in conjunction with the above information.
ITEM 7.
ITEM 7. Management's Discussion and Analysis of Results of Operations and Financial Condition.
LG&E Energy:
GENERAL
The following discussion and analysis by management focuses on those factors that had a material effect on the LG&E Energy's financial results of operations and financial condition during 1999, 1998 and 1997 and should be read in connection with the consolidated financial statements and notes thereto. As set forth in the discussion concerning the Discontinuance of the Merchant Energy Trading and Sales Business below, future financial results from the Company's operations will continue to reflect the results from its portfolio of investments in electric generation, gas distribution and other energy-related businesses in addition to the financial results provided by the Company's regulated utilities, LG&E and KU.
Some of the following discussion may contain forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words "anticipate," "expect," "estimate," "objective," "possible," "potential" and similar expressions. Actual results may vary materially. Factors that could cause actual results to differ materially include: general economic conditions; business and competitive conditions in the energy industry; changes in federal or state legislation; unusual weather; actions by state or federal regulatory agencies; and other factors described from time to time in LG&E Energy's reports to the Securities and Exchange Commission, including Exhibit 99.01 to LG&E Energy's Annual Report on Form 10-K for the year ended December 31, 1998.
MERGERS AND ACQUISITIONS
On February 28, 2000, the Company announced that its Board of Directors accepted an offer to be acquired by PowerGen for cash of approximately $3.2 billion or $24.85 per share and the assumption of $2.2 billion of the Company's debt. Pursuant to the acquisition agreement, among other things, LG&E Energy will become a wholly owned subsidiary of PowerGen and its U.S. headquarters. The Utility Operations of the Company will continue their separate identities and serve customers in Kentucky and Virginia under their present names. The preferred stock and debt securities of the Utility Operations will not be affected by this transaction resulting in the Utility Operations' obligation to continue to file SEC reports. The acquisition is expected to close later in 2000, shortly after all of the conditions to consummation of the acquisition are met. Those conditions include,
LG&E Energy: (cont.):
without limitation, the approval of the holders of a majority of the outstanding shares of common stock of each of LG&E Energy and PowerGen, the receipt of all necessary governmental approvals and the making of all necessary governmental filings, including approvals of various regulators in Kentucky and Virginia under state utility laws, the approval of the FERC under the FPA, the approval of the SEC under the PUHCA of 1935, and the filing of requisite notifications with the Federal Trade Commission and the Department of Justice under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, and the expiration of all applicable waiting periods thereunder. Shareholder meetings to vote upon the approval of the Acquisition are expected to be held during the second quarter of 2000 for both LG&E Energy and PowerGen. During the first quarter of 2000, the Company expensed approximately $1.0 million relating to the PowerGen transaction. The foregoing description of the acquisition does not purport to be complete and is qualified in its entirety by reference to LG&E Energy's current reports on Form 8-K, filed February 29, 2000, with the SEC.
In July 1999, the Company purchased 100% of the outstanding common stock of CRC for initial consideration of $45.6 million and retirement of approximately $35.3 million in CRC debt. CRC, based in Houston, Texas, is a provider of specialized equipment and services used in the construction and rehabilitation of gas and oil transmission pipelines. The purchase agreement provides for future annual earn-out payments to the previous owners based on CRC's meeting certain financial targets over the period ending March 31, 2002, or, under certain circumstances, a change in control of LG&E Energy may accelerate the earnout. The agreement capped the total of these payments at $34.3 million. The Company accounted for the acquisition using the purchase method and recorded goodwill of approximately $42.1 million. Additional goodwill will be recorded contingent upon future earn-out payments. Goodwill is being amortized over a period of twenty years.
In March 1999, the Company acquired an indirect 20% ownership interest in Gas BAN, a natural gas distribution company that serves 1.1 million customers in the northern portion of the province of Buenos Aires, Argentina. The purchase price totaled $74.3 million, including transaction costs, which has been reflected in investments in unconsolidated ventures in the accompanying balance sheet. The Company records its share of earnings using the equity method. The purchase price exceeded the underlying equity in Gas BAN by $13.0 million. The Company allocated this difference to the assets and liabilities acquired based on their preliminary estimated fair values.
Effective May 4, 1998, following the receipt of all required state and federal regulatory approvals, LG&E Energy and KU Energy merged, with LG&E Energy as the surviving corporation. The accompanying consolidated financial statements reflect the accounting for the merger as a pooling of interests and are presented as if the companies were combined as of the earliest period presented. However, the financial information is not necessarily indicative of the results of operations, financial position or cash flows that would have occurred had the merger been consummated for the periods for which it is given effect, nor is it necessarily indicative of future results of operations, financial position, or cash flows. The financial statements reflect the conversion of each outstanding share of KU Energy common stock into 1.67 shares of LG&E Energy common stock. The outstanding preferred stock of LG&E and KU was not affected by the merger. See Note 2 of LG&E Energy's Notes to Financial Statements under Item 8.
DISCONTINUANCE OF MERCHANT ENERGY TRADING AND SALES BUSINESS
Effective June 30, 1998, the Company discontinued its merchant energy trading and sales business. This business consisted primarily of a portfolio of energy marketing contracts entered into in 1996 and early 1997, nationwide deal origination and some level of speculative trading activities, which were not directly supported by the Company's physical assets. The Company's decision to discontinue these operations was primarily based on the impact that volatility and rising prices in the power market had on its portfolio of energy marketing
LG&E Energy: (cont.):
contracts. Exiting the merchant energy trading and sales business enabled the Company to focus on optimizing the value of physical assets it owns or controls, and reduced the earnings impact on continuing operations of extreme market volatility in its portfolio of energy marketing contracts. The Company continues to settle commitments that obligate it to buy and sell natural gas and electric power. If the Company is unable to dispose of these commitments or assets it will continue to meet its obligations under the terms of the contracts. The Company, however, has maintained sufficient market knowledge, risk management skills, technical systems and experienced personnel to maximize the value of power sales from physical assets it owns or controls, including LG&E, KU and WKE.
As a result of the Company's decision to discontinue its merchant energy trading and sales activity, and the initial decision to sell the associated gas gathering and processing business, the Company recorded an after-tax loss on disposal of discontinued operations of $225 million in the second quarter of 1998. The loss on disposal of discontinued operations resulted primarily from several fixed-price energy marketing contracts entered into in 1996 and early 1997, including the Company's long-term contract with OPC. Other components of the write-off included costs relating to certain peaking options, goodwill associated with the Company's 1995 purchase of merchant energy trading and sales operations and exit costs.
At the time the Company decided to discontinue its merchant energy trading and sales business, it also decided to sell its natural gas gathering and processing business. Effective June 30, 1999, the Company decided to retain this business. The accompanying financial statements reflect the reclassification of the natural gas gathering and processing business as continuing operations for all periods presented. Approximately $800,000 of net losses charged to the loss on disposal of discontinued operations was reclassified to continuing operations in the accompanying income statement in each of 1999 and 1998 related to the natural gas gathering and processing business. See Note 4 of LG&E Energy's Notes to Financial Statements under Item 8.
In the fourth quarter of 1999, the Company received an adverse decision from the arbitration panel considering its contract dispute with OPC, which was commenced by the Company in April 1998. As a result of this adverse decision, higher than anticipated commodity prices, increased load demands, and other factors, the Company increased its after-tax accrued loss on disposal of discontinued operations by $175 million. The additional write-off included costs related to the remaining commitments in its portfolio and exit costs expected to be incurred to serve those commitments. Although the Company used what it believes to be appropriate estimates for future energy prices, among other factors, to calculate the net realizable value of discontinued operations, there are inherent limitations in models to accurately predict future commodity prices, load demands and other events that could impact the amounts recorded by the Company.
Total pretax charges against the accrued loss on disposal of discontinued operations through December 31, 1999, include $251.0 million for commitments prior to disposal, $69.6 million for transaction settlements, $11.1 million for goodwill, and $30.5 million for other exit costs. While the Company has been successful in settling portions of its discontinued operations, significant assets, operations and obligations remain. The Company continues to manage the remaining portfolio and believes it has hedged certain of its future obligations through various power purchase commitments and planned construction of physical assets. Management cannot predict the ultimate effectiveness of these hedges.
The pretax net fair value of the remaining commitments as of December 31, 1999, are currently estimated to be approximately $46 million in 2000, $37 million to $54 million each year in 2001 through 2004 and $7 million in the aggregate thereafter.
As of December 31, 1999, the Company's discontinued operations were under various contracts to buy and sell
LG&E Energy: (cont.):
power and gas with net notional amounts of 22.1 million Mwh's of power and 44.3 million Mmbtu's of natural gas with a volumetric weighted-average period of approximately 37 and 44 months, respectively. These notional amounts are based on estimated loads since various commitments do not include specified firm volumes. The Company is also under contract to buy or sell coal and SO2 allowances in support of its power contracts. Notional amounts reflect the nominal volume of transactions included in the Company's price risk management commitments, but do not reflect actual amounts of cash, financial instruments, or quantities of the underlying commodity which may ultimately be exchanged between the parties.
As of January 26, 2000, the Company estimates that a $1 change in electricity prices and a 10-cent change in natural gas prices across all geographic areas and time periods could change the value of the Company's remaining energy portfolio by approximately $4.9 million. In addition to price risk, the value of the Company's remaining energy portfolio is subject to operational and event risks including, among others, increases in load demand, regulatory changes, and forced outages at units providing supply for the Company. As of January 26, 2000, the Company estimates that a 1% change in the forecasted load demand could change the value of the Company's remaining energy portfolio by $8.2 million. See Notes 3 and 18 of LG&E Energy's Notes to Financial Statements under Item 8.
The Company reclassified its financial statements for prior periods to present the operating results, financial position and cash flows of these businesses as discontinued operations. See Notes 1 and 3 of LG&E Energy's Notes to Financial Statements under Item 8 for more information.
RESULTS OF OPERATIONS
Earnings Per Share
Continuing operations for 1999 produced basic earnings per share of $1.82, an increase of 60 cents from $1.22 earned from continuing operations in 1998, after merger-related costs and environmental cost recovery refunds of approximately 43 cents and 12 cents, respectively. Earnings in both 1999 and 1998 include certain non-recurring items relating to rate refunds and gains. Excluding the effects of rate refunds in 1999 of 5 cents, and gains in 1999 and 1998 related to the Company's investment in the Rensselaer power facility of approximately 7 cents and 16 cents, respectively, earnings for 1999 were $1.80 per share compared with $1.61 in 1998, an increase of 19 cents or 12%. The 19 cents per share increase was primarily driven by the Company's non-utility operations including its 1999 acquisitions of Gas BAN and CRC, strong sales and excellent operating performance at WKE, and improved operating results at the Company's other Argentine gas operations. The Company's utility operations earnings from continuing operations for 1999 and 1998 were approximately the same.
Continuing operations for 1998 produced basic earnings per share of $1.22, before a decrease of 6 cents due to cumulative effect of an accounting change, a decrease of 39 cents per share from $1.61 earned from continuing operations in 1997. Earnings for 1998 include non-recurring charges for merger-related costs and environmental cost recovery refunds of approximately 43 cents and 12 cents, respectively. Excluding these non-recurring charges, earnings per share from continuing operations for 1998 were $1.78, an increase of 17 cents over 1997. The 17 cent per share increase resulted from a 10 cent increase in core domestic utility business and a 14 cent increase in non-utility business, partially offset by an increase in corporate and other expenses of 7 cents. The 1998 non-utility results included 16 cents relating to the Rensselaer power purchase contract settlement, 3 cents for first-year earnings related to the Big Rivers transactions, 1 cent due to a full year of operations and an increase in core business of the Company's Argentine operations, partially offset by an increase in non-utility expenses of 4 cents, primarily related to the loss on disposition of our gas-fired power
LG&E Energy: (cont.):
plant in San Miguel, Argentina and, the write-off of our WPP 94 investment.
In the fourth quarter of 1999, the Company increased its after-tax accrued loss on disposal of discontinued operations by $175 million ($1.35) per share. This increase was triggered by an adverse decision in the arbitration proceedings with OPC and resulted from higher-than-anticipated commodity prices, increased load demands and other factors. In June 1998, after the Company's decision to exit the merchant energy trading and sales business, the Company recorded an after-tax accrual for disposal of discontinued operations of approximately $224 million ($1.72) and reclassified approximately $23 million ($0.17) of losses due to merchant energy trading and sales to loss from discontinued operations. See Note 3 of LG&E Energy's Notes to Financial Statements under Item 8 for a discussion of the Company's losses related to its discontinued operations in 1999 and 1998.
Electric and Gas Utility Results
Revenues
A comparison of utility revenues for the years 1999 and 1998, excluding provisions recorded for rate refunds in 1999 and 1998, with the immediately preceding year reflects both increases and decreases, which have been segregated by the following principal causes (in thousands of $):
Electric revenues increased in 1999 primarily due to wholesale electric sales and increased retail sales volumes, partially offset by the PBR and merger surcredit bill reductions. Wholesale sales increased in 1999 due to larger amounts of power available for off-system sales, and an increase in the unit price of electricity sold. Gas revenues decreased primarily as a result of lower gas supply costs billed to customers through the gas supply clause, partially offset by increased gas sales in 1999 due to colder weather.
Electric retail sales increased primarily due to the warmer weather in 1998 as compared to 1997. Wholesale sales increased due to larger amounts of power available for off-system sales, and an increase in the unit price of the sales. Gas retail sales decreased from 1997 due to the warmer seasonal weather in 1998. Gas wholesale sales increased to $8.7 million in 1998 from zero in 1997 due to the implementation of LG&E's gas performance-based ratemaking mechanism.
LG&E Energy: (cont.):
Expenses
Fuel for electric generation and gas supply expenses comprise a large component of the Company's total operating costs. LG&E's and KU's electric rates contain an FAC and LG&E's gas rates contain a GSC, whereby increases or decreases in the cost of fuel and gas supply are reflected in LG&E's and KU's rates, subject to approval by the Kentucky Commission, the Virginia Commission and FERC. In July 1999, the Kentucky Commission approved LG&E's and KU's joint filing on PBR resulting in the discontinuance of the FAC. In January 2000, the Kentucky Commission rescinded its approval of LG&E's and KU's joint PBR filing and ordered the reinstatement of the FAC. See Note 6 for a further discussion of the PBR and the FAC.
Fuel for electric generation increased $6.9 million in 1999 primarily due to an increase in generation to support increased electric sales at LG&E ($7.4 million) and KU ($5.1 million) offset partially by a lower cost of coal burned at LG&E ($3.0 million) and at KU ($2.6 million). Fuel for electric generation increased $34.1 million in 1998 primarily due to an increase in generation to support increased electrical sales at KU ($27.3 million) and a higher cost of coal burned at LG&E ($6.6 million). LG&E's average delivered cost per ton of coal purchased was $21.49 in 1999, $22.38 in 1998 and $21.66 in 1997. KU's average delivered cost per ton of coal purchased was $26.65 in 1999, $26.97 in 1998 and $27.97 in 1997.
Power purchased increased $219.9 million (147.3%) in 1999 primarily due to increased purchases to serve native load customers and off-system sales activity. Power purchased increased $59.5 million in 1998 to support the increase in wholesale sales and due to increases in the unit price of purchases.
Gas supply expenses decreased $11.1 million (8.9%) in 1999 primarily due to a decrease in cost of net gas supply ($17.1 million), partially offset by an increase in the volume of gas delivered to the distribution system ($6 million). Gas supply expenses decreased $33 million (21%) in 1998 primarily due to a decrease in the volume of gas delivered to the distribution system. The average unit cost per Mcf of purchased gas was $2.99 in 1999, $3.05 in 1998 and $3.46 in 1997.
Operation and maintenance expenses decreased $14.3 million (3.3%) in 1999 primarily due to decreased costs to operate LG&E's electric generating plants ($5.7 million), lower administrative costs at LG&E and KU ($7.0 million) and lower costs to maintain KU's electric generating plants ($3.3 million). Operation and maintenance expenses increased $14.6 million (3.8%) in 1998 over 1997 because of increased costs to operate and maintain LG&E's electric generating plants ($8.8 million), amortization of deferred merger costs ($3.8 million), and an increase in storm damage expenses ($1.4 million).
Depreciation and amortization increased $7.3 million (4.1%) in 1999 because of additional utility plant in service. Depreciation and amortization increased $2.7 million (1.5%) in 1998 because of additional utility plant in service.
The companies incurred a pre-tax charge in the second quarter of 1998 for costs associated with the merger of LG&E Energy and KU Energy of $53.9 million (of this amount, $32.1 million was for LG&E, and $21.8 million was for KU). The amount charged is in excess of the amount permitted to be deferred as a regulatory asset by the Kentucky Commission.
Interest charges for 1998 decreased $3.9 million (7%) due to the retirement of LG&E's 6.75% Series First Mortgage Bonds and lower interest rates. LG&E's embedded cost of long-term debt was 5.46% at December 31, 1999 and 5.57% at December 31, 1998. KU's embedded cost of long-term debt was 7.00% at December 31, 1999 and 6.99% at December 31, 1998.
LG&E Energy: (cont.):
Variations in income tax expenses are largely attributable to changes in pre-tax income as well as non-deductible merger expenses.
The rate of inflation may have a significant impact on the Company's utility operations, its ability to control costs and the need to seek timely and adequate rate adjustments. However, relatively low rates of inflation in the past few years have moderated the impact on current operating results.
LG&E Capital Corp. and Other Results
Capital Corp., the holding company for all the Company's non-utility investments other than trading operations, conducts its operations through three principal segments: Power Operations, WKE and Argentine Gas Distribution. Involvement in these and other non-utility businesses represents the Company's commitment to understand, respond to, and capitalize on the opportunities presented by an emerging competitive energy services industry. The Power Operations develop, operate, maintain and own interests in domestic and international power generation facilities that sell electric and steam energy to utility and industrial customers. WKE leases and operates the generating facilities of Big Rivers. Argentine Gas Distribution owns interests in three natural gas distribution companies in Argentina. Capital Corp. and LEM are also engaged in other non-utility activities including: providing specialized equipment and services used in construction and rehabilitation of gas and oil transmission pipelines; the gathering, processing, storing and transportation of natural gas; commercial and retail initiatives designed to assess the energy and utility needs of large commercial and industrial entities; providing maintenance and repair services for customers' major household appliances; and, the asset optimization of the Company's generation assets. See Notes 2, 5, 9, 10, 18 and 20 of LG&E Energy's Notes to Financial Statements under Item 8.
Power Operations
Revenues
Revenues from Power Operations, comprised mainly of contractual revenues from various power plant operations, were approximately the same for the years 1997 to 1999. See Note 9 of LG&E Energy's Notes to Financial Statements under Item 8.
Equity in earnings of unconsolidated ventures includes the Company's share of earnings from the ventures in which it maintains an equity interest, but does not consolidate the results of operations. Equity in earnings for 1999 of $40.9 million was $30.4 million less than 1998, primarily due to transactions recorded by its Rensselaer venture in 1999 and 1998, including a gain on a power purchase contract settlement in 1998, the sale of the Company's ownership interest in March, and a full year of earnings in 1998 versus 2 1/2 months in 1999. Without the Rensselaer transactions in 1999 and 1998, equity in earnings of the Company's other ventures were approximately the same. Equity in earnings for 1998 were $50.8 million higher (247%) than in 1997 due primarily to the Rensselaer power purchase contract settlement and an arbitration award received by the Frederickson, Washington, venture. These increases were partially offset by a write-off of the Company's investment in a wind power venture. See Notes 9 and 20 of LG&E Energy's Notes to Financial Statements under Item 8.
Expenses
Direct costs of revenues are primarily comprised of labor and related expenses associated with the Company 's operation of various power plants. Direct costs increased by $1.7 million in 1999 to $15.1 million, primarily
LG&E Energy: (cont.):
due to development expenses of the Gregory, Texas, project. These costs were approximately the same in 1998 and 1997.
Operation and maintenance expenses were approximately the same for all periods presented. Depreciation and amortization decreased by $1.7 million in 1999 primarily due to the write-off of certain intangible assets in 1998 after the Rensselaer power purchase contract settlement and the sale of a 114 Mw gas-fired power plant in San Miguel, Argentina, offset by an additional write-off of intangible assets upon the sale of the Rensselaer venture in March 1999. Depreciation and amortization increased $3.3 million in 1998 due to the write-off of certain intangible assets and capitalized interest associated with the sale of the Company's interest in the San Miguel, Argentina, venture and the closure of the Rensselaer power purchase contract settlement. See Note 9 of LG&E Energy's Notes to Financial Statements under Item 8.
Western Kentucky Energy
WKE's 1999 results include twelve-months of operations versus 5 1/2 months in 1998, the primary driver in most year-over-year increases. Total revenues increased by $205.3 million (159%) to $333.8 million due primarily to a full year of operation in 1999 and higher power sales prices in the summer of 1999. Cost of revenues increased by $136.6 million (186%) to $209.7 million due primarily to a full year of operation in 1999 and higher purchase power costs. Operations and maintenance expenses increased by $56.3 million (127%) to $103.1 million primarily due to a full year of operation in 1999 and higher depreciation expenses related to an increase in capital assets. Net interest expense increased by $1.5 million (58%) to $4.1 million related to the cost of carrying its debt for a full year.
During WKE's partial year of operations in 1998 it reported a solid performance with revenues of $128.5 million. WKE's cost of revenues, primarily composed of fuel and purchased power expenses, amounted to $73.1 million for the year. Operation and maintenance expenses of $45.4 million include $12.8 million of rent expense associated with the lease of Big Rivers' operating facilities. WKE incurred interest expense of approximately $2.6 million associated with borrowings to fund the initial purchase of certain materials and supplies from Big Rivers and to prepay the first two years' lease payments totaling $55.9 million. See Note 5 of LG&E Energy's Notes to Financial Statements under Item 8.
Argentine Gas Distribution
The Company has interests in three Argentine natural gas distribution companies: Centro and Cuyana, both acquired in February 1997, and Gas BAN acquired in March 1999. Centro is consolidated within the Company's results while Cuyana's and Gas BAN's results are recorded using the equity method of accounting. The Company's investments in Argentina continue to contribute to non-utility operations, with Centro's revenues increasing by $8 million (5%) in 1999 and $21 million (16%) in 1998. The increase in 1999 was primarily driven by higher per customer consumption as a result of colder than normal weather. 1998's increase was due to a full year of operations versus 10 1/2 months in 1997, higher per customer consumption and an increase in the customer base. Centro's operating expenses increased by $.8 million (3%) in 1999 due to higher consumption. Centro's 1998 operating expenses increased by $2.4 million (8%) due to a full year of operations in 1998. Equity in earnings for 1999 increased by $6.3 million (253%) due to the Gas BAN acquisition completed in March 1999. Equity in earnings of Cuyana were approximately the same in all periods presented. See Notes 2 and 9 of LG&E Energy's Notes to Financial Statements under Item 8.
LG&E Energy: (cont.):
Other
The Company has entered into various initiatives to position itself for growth in the energy industry, including: providing specialized equipment and services used in construction and rehabilitation of gas and oil transmission pipelines; the gathering, processing, storing and transportation of natural gas; consulting services designed to assess the energy and utility needs of large commercial and industrial entities; providing maintenance and repair services for customers' major household appliances; and, the optimizing of the Company's generation assets. The commercial initiatives represent new businesses and products designed to leverage the Company's existing assets and experience, and to gain access to new markets. Our retail initiatives enhance value for LG&E's and KU's customers and are designed to help ensure that LG&E and KU remain the utility of choice within their respective service areas when a fully competitive industry framework takes shape. These commercial and retail initiatives have not had a significant impact on the Company's financial position or required significant capital investment over the last three years. We remain optimistic that these non-traditional ventures will add to our knowledge base as well as our financial results in the future.
The Company's interest costs increased by $22.7 million (83%) from 1998 to 1999 and $5.0 million (5%) from 1997 to 1998. The 1999 increase was primarily due to the funding of discontinued operations and LG&E Energy's operating expenses, along with funding the Gas BAN and CRC acquisitions. The increase in 1998 was primarily due to the funding of discontinued operations and LG&E Energy's operating expenses. See Notes 2, 3, 7 and 16 of LG&E Energy's Notes to Financial Statements under Item 8.
LIQUIDITY AND CAPITAL RESOURCES
The Company uses net cash generated from its operations and external financing to fund construction of plant and equipment, equity investments in energy-related growth or acquisition opportunities, liquidity needs of its discontinued energy marketing and trading activities and operating its existing businesses. The Company believes that such sources of funds will be sufficient to meet the needs of its business in the foreseeable future.
Operating Activities
Cash provided by operations was $343.3 million, $209.6 million and $333.7 million in 1999, 1998 and 1997, respectively. The 1999 increase was primarily due to an increase in net income, a net decrease in non-cash income statement items, including the recording of the reserve on loss on disposal of discontinued operations, and a net increase in net current assets, including increases in accounts payable, accrued taxed and interest, and materials and supplies. The 1998 decrease was primarily due to a decrease in net income and an increase in materials and supplies, partially offset by a net increase in non-cash income statement items, including the recording a loss on disposal of discontinued operations and increases in accounts payable and accrued taxes and interest.
Investing Activities
LG&E Energy's primary use of funds continues to be for capital expenditures and investments in subsidiaries/unconsolidated ventures. Capital expenditures were $382.6 million, $343.6 million and $225.7 million in 1999, 1998 and 1997, respectively. The Company expects its capital expenditures for 2000 and 2001 will total approximately $850 million, consisting primarily of construction costs associated with installation of low nitrogen oxide burner systems for LG&E, KU and WKE as described in the section titled "Environmental Matters."
LG&E Energy: (cont.):
Net cash used for investment activities increased by $115.4 million in 1999 compared to 1998. The increase was primarily due to the acquisition of CRC, the 20% investment in Gas BAN, and an increase in construction expenditures. This increase was partially offset by proceeds received from the sales of the Company's ownership interest in Rensselaer and five combustion turbines.
Net cash used for investment activities decreased by $45.5 million in 1998 compared to 1997 primarily due to a decrease in investment in subsidiaries and unconsolidated ventures partially offset by an increase in construction expenditures.
Financing Activities
Cash inflows from financing activities were $84.9 million, $111.6 million and $42.8 million in 1999, 1998 and 1997, respectively. In 1999, total debt increased by $284.9 million to $2,160.8 at December 31, 1999. The increase was primarily due to funding operating expenses, discontinued operations and business development activities including the acquisitions of CRC and Gas BAN.
As of December 1999, the Company had committed lines of credit aggregating $900.0 million with various banks. Unused capacity under these lines totaled $395.6 million after considering the commercial paper support and approximately $51.7 million in letters of credit securing on- and off-balance sheet commitments. The credit lines will expire at various times from 2000 through 2002. Management expects to renegotiate the lines as they expire.
The lenders under the credit facilities, the commercial paper facility, the medium-term notes for Capital Corp. and the lessors of the operating lease for the Monroe plant are entitled to the benefits of a Support Agreement with LG&E Energy. See Note 18 of LG&E Energy's Notes to Financial Statements under Item 8.
Future Capital Requirements
Future utility capital requirements may be affected in varying degrees by factors such as load growth, changes in construction expenditure levels, rate actions by regulatory agencies, new legislation, market entry of competing electric power generators, changes in environmental regulations and other regulatory requirements. Other future capital funding requirements are dependent upon the identification of suitable investment and acquisition opportunities. The Company anticipates funding these investment opportunities through net cash generated from operations, additional debt or an issuance of preferred stock.
LG&E Energy: (cont.):
The Company's debt ratings as of February 16, 2000, were:
Moody's S&P D&P ------- --- ---
LG&E First mortgage bonds A1 A+ AA- Unsecured debt A2 A- A+ Preferred stock a2 BBB+ A Commercial paper P-1 A-1 D-1
KU First mortgage bonds A1 A+ AA- Preferred stock a2 BBB+ A Commercial paper P-1 A-1 D-1
Capital Corp. Medium-term notes A3 A- A- Commercial paper P-2 A-1 D-1-
The ratings stated above reflect the downgrades received by the Company following an adverse decision in the OPC arbitration case, which resulted in an additional $175 million after-tax charge to increase the Company's discontinued operations reserve, and the PBR-related order received from the Kentucky Commission to reduce base rates at LG&E and KU by $27.2 million and $36.5 million, respectively. As of March 21, 2000, Moody's, S&P and D&P had LG&E Energy, LG&E, KU and Capital Corp. on Credit Watch with negative implications. Based upon the downgrades received the Company's cost of funds could increase by .05% to .12% on short-term borrowings and .10% on new long-term borrowings. These ratings reflect the views of Moody's, S&P and D&P. A security rating is not a recommendation to buy, sell or hold securities and is subject to revision or withdrawal at any time by the rating agency.
Market Risks
LG&E Energy is exposed to market risks in both its regulated and non-utility operations. Both operations are exposed to market risks from changes in interest rates and commodity prices, while the non-utility operations are also exposed to changes in foreign exchange rates. To mitigate changes in cash flows attributable to these exposures, the Company has entered into various derivative instruments. Derivative positions are monitored using techniques that include market value and sensitivity analysis.
Interest Rate Sensitivity
The Company has short-term and long-term variable rate debt obligations outstanding. At December 31, 1999, the potential change in interest expense associated with a 1% change in base interest rates of the Company's unswapped debt is estimated at $7.0 million. These swaps hedge specific debt issuance and consistent with management's designation are accorded hedge accounting treatment.
As of December 31, 1999, the Company had swaps with a combined notional value of $404 million. LG&E and Capital Corp. have entered into $251 million of swaps to exchange their floating-rate interest payments for fixed interest payments to reduce the impact of interest rate changes on their Pollution Control Bonds and commercial paper program, respectively. LEC and KU have entered into $153 million to convert some of its fixed rate debt to variable rate debt. As of December 31, 1999, 31% of the outstanding variable interest rate
LG&E Energy: (cont.):
borrowings were converted to fixed interest rates, while 11% of the outstanding fixed interest rate borrowings were converted to floating interest rates through swaps. The potential loss in fair value from these positions resulting from a hypothetical 1% adverse movement in base interest rates is estimated at $13.1 million as of December 31, 1999. Changes in the market value of these swaps if held to maturity, as the Company intends to do, will have no effect on the Company's net income or cash flow. See Note 7 of LG&E Energy's Notes to Financial Statements under Item 8.
Commodity Price Sensitivity
LG&E and KU have limited exposure to market price volatility in prices of fuel and electricity, as long as cost-based regulations exist, including the FAC and GSC. WKE is exposed to changes in fuel prices. To mitigate this risk, WKE has entered into various multi-year fuel supply contracts which expire at various times through 2003 and is also pursuing the use of alternative fuels. Realized gains and losses are recognized in the income statement as incurred. At December 31, 1999, exposure from these activities was not material to the consolidated financial statements of the Company.
Capital Corp., through its subsidiaries, operates and controls the generating capacity of Big Rivers and Henderson. Some of the excess capacity generated by these assets is currently being marketed by WKE. To mitigate residual risks relative to the movements in electricity prices, WKE has entered into primarily fixed-priced contracts for the purchase and sale of electricity through the wholesale electricity market. Realized gains and losses are recognized in the income statement as incurred. At December 31, 1999, exposure from these activities was not material to the consolidated financial statements of the Company.
The Company's discontinued merchant energy trading and sales business has exposure to market volatility in electricity prices and load requirements. See Discontinuance of Merchant Energy Trading and Sales Business under Management's Discussion and Analysis and Note 3 of LG&E Energy's Notes to Financial Statements under Item 8.
Exchange Rate Sensitivity
The Company has investments in Argentina, Canada, Spain and the UK that are not hedged. The Company relies on the Argentine peso's currency peg to the U.S. dollar to mitigate currency risk attributable to its Argentine investments and views its investments in Canada, Spain and the UK as too small to cost-effectively hedge. A 10% decline in the December 31, 1999 exchange rate for the Argentine peso, the Canadian dollar, British pound sterling and the Spanish peseta (versus the U.S. dollar) would not have a material effect on income from continuing operations.
YEAR 2000 COMPUTER SOFTWARE ISSUE
Result of Year 2000 Preparation
The remediation efforts of the Company in preparing for potential Year 2000 computer problems were successful and resulted in the Company incurring no material disruptions in services or operations. To the extent, if any, certain third parties such as interconnected utilities, key customers or suppliers still face potential Year 2000 disruptions due to incomplete remediation, the Company may still retain risk related to Year 2000 issues. The Company is not presently aware of any such situations and does not anticipate such events will have a material effect on the Company's financial condition or results of operations.
LG&E Energy: (cont.):
Cost of Year 2000 Issues
The Company's system modification costs related to the Year 2000 issue were expensed as incurred, with new system installations being capitalized pursuant to generally accepted accounting principles. See Note 1 of LG&E Energy's Notes to Financial Statements under Item 8. Through December 1999, the Company had incurred approximately $26.7 million in capital and operating costs in connection with the Year 2000 issue.
RATES AND REGULATION
LG&E and KU are subject to the jurisdiction of the Kentucky Commission in virtually all matters related to electric and gas utility regulation, and as such, their accounting is subject to SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. KU is also subject to the jurisdiction of the Virginia Commission and FERC. Given LG&E's and KU's competitive position in the market and the status of regulation in the states of Kentucky and Virginia, neither LG&E nor KU has plans or intentions to discontinue its application of SFAS No. 71. See Note 6 of LG&E Energy's Notes to Financial Statements under Item 8.
Environmental Cost Recovery
In August 1994 and May 1995, respectively, KU and LG&E implemented an ECR surcharge. The Kentucky Commission's order approving the surcharge for KU as well as the constitutionality of the surcharge was challenged by certain intervenors in Franklin Circuit Court. Decisions of the Circuit Court and the Kentucky Court of Appeals in July 1995 and December 1997, respectively, upheld the constitutionality of the ECR statute but differed on a claim of retroactive recovery of certain amounts. Based on these decisions, the Kentucky Commission ordered that certain surcharge revenues collected by LG&E and KU be subject to refund pending final determination of all appeals.
In December 1998, the Kentucky Supreme Court rendered an opinion upholding the constitutionality of the surcharge statute but denied recovery of costs associated with pre-1993 environmental projects through the ECR. The court remanded the case to the Kentucky Commission to determine amounts to be refunded for revenues collected for such pre-1993 environmental projects. Accordingly, the Company recorded a provision for rate refunds of $26 million in December 1998.
The parties to the proceedings reached a settlement agreement that was approved in a Final Order issued by the Kentucky Commission in August 1999. This Final Order resulted in the reversal of approximately $0.9 million of the provision for rate refunds established by KU and LG&E in December 1998. The refund is being applied to customers' bills during the twelve-month period beginning October 1999.
Future Rate Regulation
In October 1998, LG&E and KU filed applications with the Kentucky Commission for approval of a new method of determining electric rates that sought to provide financial incentives for LG&E and KU to further reduce customers' rates. The filing was made pursuant to the September 1997 Kentucky Commission order approving the merger of LG&E Energy and KU Energy, wherein the Kentucky Commission directed LG&E and KU to indicate whether they desired to remain under traditional rate of return regulation or commence non-traditional regulation. The proposed ratemaking method, known as PBR, included financial incentives for LG&E and KU to reduce fuel costs and increase generating efficiency, and to share any resulting savings with customers. Additionally, the PBR proposal provided for financial penalties and rewards to assure continued high quality service and reliability.
LG&E Energy: (cont.):
In April 1999, LG&E and KU filed a joint agreement among the companies and the Kentucky Attorney General to adopt the PBR plan subject to certain amendments. The amended filing included requested Kentucky Commission approval of a five-year rate reduction plan which proposed to reduce the electric rates of LG&E and KU by $20 million in the first year (beginning July 1999), and by $8 million annually through June 2004. The proposed amended plan also included establishment of a $6 million program for low-income customer assistance as well as extension for one additional year of both the rate cap proposal and merger savings surcredit established in the original merger plan of LG&E and KU. Under the rate cap proposal, the companies agreed, in the absence of extraordinary circumstances, not to increase base electric rates for five years following the merger and LG&E also agreed to refrain from filing for an increase in natural gas rates through June 2004.
In April 1999, the Kentucky Commission issued initial orders implementing the amended PBR plan, effective July 1999, and subject to modification. The Kentucky Commission also consolidated into the continuing PBR proceedings an earlier March 1999, rate complaint by a group of industrial intervenors, KIUC, in which KIUC requested significant reductions in electric rates. Hearings were conducted before the Kentucky Commission on LG&E's and KU's amended PBR plans and the KIUC rate reduction petitions in August and September 1999. Legal briefs of the parties were filed with the Kentucky Commission in October 1999. KIUC's position called for annual revenue reductions for LG&E and KU of $69.6 million and $61.5 million, respectively.
In January 2000, the Kentucky Commission issued Orders for LG&E and KU in the subject cases. The Kentucky Commission ruled that LG&E and KU should reduce base rates by $27.2 million and $36.5 million, respectively, effective with bills rendered beginning March 1, 2000. The Kentucky Commission eliminated the utilities' proposal to operate under its PBR plan and reinstated the FAC mechanism effective March 1, 2000. The Kentucky Commission offered the utilities the opportunity to operate under an ESM for the next three years. Under this mechanism, incremental annual earnings for each utility resulting in a rate of return either above or below a range of 10.5% to 12.5% would be shared 60% with shareholders and 40% with ratepayers.
Later in January 2000, the utilities filed motions for correction to the January 2000 orders for computational and other errors made in the Kentucky Commission's orders which produced overstatements in the base rate reductions to LG&E and KU of $1.1 million and $7.7 million, respectively. The utilities also filed motions for reconsideration with the Kentucky Commission on a number of items in the case in late January. Certain intervening parties in the proceedings have also filed motions for reconsideration asserting, among other things, that the Kentucky Commission understated the amount of base rate reductions. In February 2000, LG&E and KU accepted the Kentucky Commission's proposed ESM and filed an ESM tariff which contained detailed provisions for operation of the ESM rates. Management cannot predict final outcome of these matters before the Kentucky Commission or the timing in which resolution of these matters will ultimately be reached.
Other Rate Matters
LG&E's rates contain a DSM provision. The provision includes a rate mechanism that provides concurrent recovery of DSM costs and provides an incentive for implementing DSM programs. This program had allowed LG&E to recover revenues from lost sales associated with the DSM program (decoupling), but in 1998, LG&E and customer interest groups requested an end to the decoupling rate mechanism. In September 1998, the Kentucky Commission accepted LG&E's modified tariff discontinuing the decoupling mechanism effective as of June 1, 1998.
Since October 1997, LG&E has implemented an experimental performance-based ratemaking mechanism related to gas procurement activities and off-system gas sales only. During the three-year test period beginning October 1997, rate adjustments related to this mechanism are being determined for each 12-month period
LG&E Energy: (cont.):
beginning November 1 and ending October 31. During the first two years of the mechanism ended October 31, 1999 and 1998, LG&E recorded $2.2 million and $3.5 million, respectively, for its share of reduced gas costs. These amounts are billed to customers through the gas supply clause.
Prior to implementation of the PBR in July 1999, and following its termination in March 2000, LG&E and KU employed an FAC mechanism, which under Kentucky law allowed the utilities to recover from customers the actual fuel costs associated with retail electric sales. In February 1999, LG&E received orders from the Kentucky Commission requiring a refund to retail electric customers of approximately $3.9 million resulting from reviews of the FAC from November 1994 through April 1998, of which $1.9 million was refunded in April 1999 for the period beginning November 1994 and ending October 1996. The orders changed the utilities' method of computing fuel costs associated with electric line losses on off-system sales appropriate for recovery through the FAC. LG&E requested that the Kentucky Commission grant rehearing on the February orders, and further requested that the Kentucky Commission stay the refund requirement until it could rule on the rehearing request. The Kentucky Commission granted the request for a stay, and in March 1999 granted rehearing on the appropriate line loss factor associated with off-system sales for the 18-month period ended April 1998. The Kentucky Commission also granted rehearing on the KIUC's request for rehearing on the Kentucky Commission's determination that it lacked authority to require the utilities to pay interest on the refund amounts. The Kentucky Commission conducted a hearing on the rehearing issues and issued a final ruling in December 1999. The Kentucky Commission agreed with LG&E 's position on the appropriate loss factor to use in the FAC computation and reduced the refund level for the 18-month period under review to approximately $800,000. LG&E implemented the refund with billings beginning in the month of January 2000. LG&E and KIUC have each filed separate appeals from the Kentucky Commission's February 1999 orders with the Franklin Circuit Court. A decision on the appeals by the Court is expected in 2000.
In July 1999, the Kentucky Commission issued a series of orders requiring KU to refund approximately $10.1 million resulting from reviews of the FAC from November 1994 to October 1998. The orders changed KU's method of computing fuel costs associated with electric line losses on off-system sales appropriate for recovery through the FAC, and KU's method for computing system line losses for the purpose of calculating the system sales component of the FAC charge. At KU's request, in July 1999, the Kentucky Commission stayed the refund requirement pending the Kentucky Commission's final determination of any rehearing request that KU may file. In August 1999, KU filed its request for rehearing of the July orders.
In August 1999, the Kentucky Commission issued a Final Order in the KU proceedings, agreeing, in part, with KU's arguments outlined in its Petition for Rehearing. While the Kentucky Commission confirmed that KU should change its method of computing the fuel costs associated with electric line losses, it agreed with KU that the line loss percentage should be based on KU's actual line losses incurred in making off-system sales rather than the percentage used in its Open Access Transmission Tariff. The Kentucky Commission also upheld its previous ruling concerning the computation of system line losses in the calculation of the FAC. The net effect of the Kentucky Commission's Final Order was to reduce the refund obligation to $5.8 million from the original Order amount of $10.1 million. In August 1999, LG&E and KU each recorded its estimated share of anticipated FAC refunds of $8.7 million. KU began implementing the refund in October and will continue the refund through September 2000. Both KU and the KIUC have appealed the Order to the Franklin Circuit Court. A decision is not expected on the appeal until later in 2000.
LG&E intends to file before the end of the first quarter an application with the Kentucky Commission for authority to increase its natural gas rates in order to recoup higher costs for providing natural gas distribution services. LG&E expects implementation before the end of 2000.
LG&E Energy: (cont.):
Kentucky PSC Administrative Case for Affiliate Transactions
In December 1997, the Kentucky Commission opened Administrative Case No. 369 to consider Kentucky Commission policy regarding cost allocations, affiliate transactions and codes of conduct governing the relationship between utilities and their non-utility operations and affiliates. The Kentucky Commission intends to address two major areas in the proceedings: the tools and conditions needed to prevent cost shifting and cross-subsidization between regulated and non-utility operations; and whether a code of conduct should be established to assure that non-utility segments of the holding company are not engaged in practices that could result in unfair competition caused by cost shifting from the non-utility affiliate to the utility. In September 1998, the Kentucky Commission issued a draft code of conduct and cost allocation guidelines. In January 1999, the Company, as well as all parties to the proceeding, filed comments on the Kentucky Commission draft proposals. In December 1999, the Kentucky Commission issued guidelines on cost allocation and held a hearing in January 2000, on the draft code of conduct. Management does not expect the ultimate resolution of this matter to have a material adverse effect on the Company's financial position or results of operations.
Environmental Matters
The Act imposed stringent new SO2 and NOx emission limits on electric generating units. LG&E previously had installed scrubbers on all of its generating units, while KU met its Phase I SO2 requirements primarily through installation of a scrubber on Ghent Unit 1. The Company's combined strategy for Phase II, commencing January 1, 2000, is to use accumulated emissions allowances to delay additional capital expenditures and may also include fuel switching or the installation of additional scrubbers. LG&E, KU, and WKE met the NOx emission requirements of the Act through installation of low-NOx burner systems. The Company's compliance plans are subject to many factors including developments in the emission allowance and fuel markets, future regulatory and legislative initiatives, and advances in clean air control technology. The Company will continue to monitor these developments to ensure that its environmental obligations are met in the most efficient and cost-effective manner.
In September 1998, the EPA announced its final "NOx SIP call" rule requiring significant additional reductions in NOx emissions by May 2003, in order to mitigate alleged ozone transport to the Northeast. While each of the 22 states covered by the rule is free to allocate its assigned NOx reductions among various emissions sectors as it deems appropriate, the regulation may ultimately require electric generating units to reduce their NOx emissions to 0.15 lb./Mmbtu - an 85% reduction from 1990 levels. In related proceedings in response to petitions filed by various Northeast states, in December 1999, EPA issued a final rule directing similar NOx reductions from a number of specifically named electric generating units including all LG&E and KU stations in the eastern half of Kentucky. Additional petitions currently pending before EPA may potentially result in orders encompassing the remaining KU and WKE stations. Several states, various labor and industry groups, and individual companies have appealed both EPA rulings to the U.S. Court of Appeals for the Washington D.C. Circuit. Management is currently unable to determine the outcome or exact impact of this matter until such time as the courts rule on the pending legal challenges and the states implement the final regulatory mandate. However, if the 0.15 lb. target is ultimately imposed, LG&E, KU, and WKE and the independent power projects in which the Company has an interest will be required to incur significant capital expenditures and increased operation and maintenance costs for additional controls.
Subject to further study, analysis, and the outcome of pending litigation against the EPA, the Company estimates that it may incur approximate capital costs for NOx compliance ranging from $300 million to reduce emissions to the level of .25 lb./Mmbtu (Commonwealth of Kentucky's proposed NOx compliance level) to $550 million to reduce emissions to the level of .15 lb./Mmbtu (current EPA regulations). These costs would
LG&E Energy: (cont.):
generally be incurred beginning in 2000. The Company believes its costs in this regard to be comparable to those of similarly situated utilities with like generation assets. LG&E and KU anticipate that such capital and operating costs are the type of costs that are eligible for recovery from customers under their environmental surcharge mechanisms and believe that a significant portion of such costs could be recovered. However, Kentucky Commission approval is necessary and there can be no guarantee of recovery.
The Company is also addressing other air quality issues. First, the Company is monitoring the status of EPA's revised NAAQS for ozone and particulate matter. In May 1999, the Washington D.C. Circuit remanded the final rule and directed EPA to undertake additional rulemaking efforts. The Company continues to monitor EPA actions to challenge that ruling. Second, the Company was notified by regulatory agencies that the Cane Run Station may be the source of a potential exceedance of the NAAQS that could require the Company to incur additional capital expenditures or accept certain emissions limitations. After reviewing additional modeling information submitted by the Company, in January 2000, EPA concluded that the Cane Run Station does not contribute to any potential NAAQS exceedance and that no further action is required from the Company. Third, the Company is working with regulatory authorities to review the effectiveness of remedial measures aimed at controlling particulate emissions from its Mill Creek Station. The Company previously settled a number of property damage claims from adjacent residents and completed significant plant modifications as part of its ongoing capital construction program.
The Company owns or formerly owned several properties which contained past MGP operations. Various contaminants are typically found at such former MGP sites and environmental remediation measures are frequently required. The Company has completed the cleanup of a site owned by KU and reached agreements for other parties to assume cleanup responsibility for two other sites formerly owned by LG&E. In addition, the Company recently reached an agreement with the Kentucky Division of Waste Management with respect to a third LG&E-owned site in which the Company committed to impose certain property restrictions and conduct additional monitoring in lieu of a cleanup. Based on currently available information, management estimates that it will incur additional MGP costs of less than $500,000. Accordingly, an accrual of $500,000 has been recorded in the accompanying financial statements. With respect to other former MGP sites no longer owned by the Company, the Company is unable to determine what, if any, additional exposure or liability it may have as it lacks complete information on current site conditions.
In October 1999, approximately 38,000 gallons of diesel fuel leaked from a cracked valve in an underground pipeline at KU's E.W. Brown Station. Under the oversight of EPA and state officials, the Company commenced immediate spill containment and recovery measures which prevented the spill from reaching the Kentucky River. The Company ultimately recovered approximately 34,000 gallons of diesel fuel. In November 1999, the Kentucky Division of Water issued a notice of violation for the incident. The Company is currently negotiating with the state in an effort to reach a complete resolution of this matter. To date the Company has incurred costs of approximately $1 million. The Company does not expect to incur any material additional amounts.
See Note 18 of LG&E Energy's Notes to Financial Statements under Item 8 for an additional discussion of the Company's environmental issues.
Public Utilities Regulatory Policies Act
Proposals have been introduced in Congress to repeal all or portions of the PURPA. PURPA and its implementing regulations require, among other things, that electric utilities purchase electricity generated by qualifying cogeneration facilities at a price based on the purchasing utility's avoided costs. The Company is the partial owner and contractual operator of several qualifying cogeneration facilities. While the Company
LG&E Energy: (cont.):
supports the repeal of PURPA, the Company intends to oppose any efforts to nullify existing contracts between electric utilities and qualifying cogeneration facilities. The Company has been involved in proceedings before FERC regarding its Southampton cogeneration facility and is in litigation with the purchasing utility of the energy from its Roanoke Valley I cogeneration facility. See Note 18 of LG&E Energy's Notes to Financial Statements under Item 8.
IMPACT OF NON-UTILITY BUSINESSES
The Company expects to continue investing in non-utility projects, including domestic and international power production, gas distribution projects and other energy-related businesses, as described in the sections titled LG&E Capital Corp. and Other Results, and Future Capital Requirements. The non-utility projects in which the Company has invested carry a higher level of risk than LG&E's or KU's traditional utility businesses. Current investments in non-utility projects are subject to competition, operating risks, dependence on certain suppliers and customers, environmental and energy regulations, as well as political and currency risks. In addition, significant expenses may be incurred for projects pursued by the Company that do not materialize. The aggregate effect of these factors creates the potential for more volatility in the non-utility component of the Company's earnings. Also, the Company may seek opportunities to divest certain of its existing non-utility assets under suitable market conditions. Accordingly, the historical operating results of the Company's non-utility businesses may not necessarily be indicative of future operating results.
FUTURE OUTLOOK
Competition and Customer Choice
LG&E Energy has moved aggressively over the past decade to be positioned for, and to help promote the energy industry's shift to customer choice and a competitive market for energy services. Specifically, the Company has taken many steps to prepare for the expected increase in competition in its regulated and non-utility energy services businesses, including support for performance-based ratemaking structures, aggressive cost reduction activities; strategic acquisitions, dispositions and growth initiatives; write-offs of previously deferred expenses; an increase in focus on commercial and industrial customers; an increase in employee training; and necessary corporate and business unit realignments. The Company continues to be active in the national debate surrounding the restructuring of the energy industry and the move toward a competitive, market-based environment. LG&E Energy has urged Congress to set a specific date for a complete transition to a competitive market, one that will quickly and efficiently bring the benefits associated with customer choice. LG&E Energy has previously advocated the implementation of this transition by January 1, 2001, and now recommends adoption of federal legislation specifying a date certain and appropriate transition regulations implementing deregulation.
In December 1997, the Kentucky Commission issued a set of principles which was intended to serve as its guide in consideration of issues relating to industry restructuring. Among the issues addressed by these principles are: consumer protection and benefit, system reliability, universal service, environmental responsibility, cost allocation, stranded costs and codes of conduct. During 1998, the Kentucky Commission and a task force of the Kentucky General Assembly each conducted proceedings, including meetings with representatives of utilities, consumers, state agencies and other groups in Kentucky, to discuss the possible structure and effects of energy industry restructuring in Kentucky.
In November 1999, the task force issued a report to the Governor of Kentucky and a legislative agency recommending no general electric industry restructuring actions during the 2000 legislative session.
LG&E Energy: (cont.):
Thus, at the time of this report, neither the Kentucky General Assembly nor the Kentucky Commission has adopted or approved a plan or timetable for retail electric industry competition in Kentucky. The nature or timing of the ultimate legislative or regulatory actions regarding industry restructuring and their impact on the Company, which may be significant, cannot currently be predicted.
LG&E:
GENERAL
The following discussion and analysis by management focuses on those factors that had a material effect on LG&E's financial results of operations and financial condition during 1999, 1998, and 1997 and should be read in connection with the financial statements and notes thereto.
Some of the following discussion may contain forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words "anticipate," "expect," "estimate," "objective," "possible," "potential" and similar expressions. Actual results may vary materially. Factors that could cause actual results to differ materially include: general economic conditions; business and competitive conditions in the energy industry; changes in federal or state legislation; unusual weather; actions by state or federal regulatory agencies; and other factors described from time to time in Louisville Gas and Electric Company's reports to the Securities and Exchange Commission, and Exhibit No. 99.01 to LG&E Energy's annual report on Form 10-K for the year ended December 31, 1998.
MERGER
Effective May 4, 1998, following the receipt of all required state and federal regulatory approvals, LG&E Energy and KU Energy merged, with LG&E Energy as the surviving corporation. The outstanding preferred stock of LG&E, a subsidiary of LG&E Energy, was not affected by the merger. See Note 2 of LG&E's Notes to Financial Statements under Item 8.
RESULTS OF OPERATIONS
Net Income
LG&E's net income increased $28.2 million for 1999, as compared to 1998, primarily due to non-recurring charges in 1998 for merger-related expenses of $23.6 million, after tax. Excluding these non-recurring charges, net income increased $4.6 million. This increase is mainly due to higher electric revenues, lower administrative costs and operating expenses at the electric generating stations, partially offset by higher maintenance expenses at the electric generating stations.
Net income decreased $35.2 million for 1998, as compared to 1997, primarily due to non-recurring charges for merger-related expenses and the ECR refund of $23.6 million and $2.7 million, after tax, respectively. Excluding these non-recurring charges, net income decreased $8.9 million. This decrease is mainly due to higher operating expenses at the electric generating stations and lower gas sales, partially offset by increased electric sales.
Revenues
A comparison of operating revenues for the years 1999 and 1998, excluding the provisions recorded for refunds
LG&E: (cont.):
in 1999 and in 1998, with the immediately preceding year reflects both increases and decreases, which have been segregated by the following principal causes (in thousands of $):
Electric revenues increased in 1999 primarily due to wholesale electric sales and higher levels of retail sales volumes, partially offset by the PBR and merger surcredit bill reductions. Wholesale sales increased in 1999 due to large amounts of power available. Gas revenues decreased primarily as a result of lower gas supply costs billed to customers through the gas supply clause, partially offset by increased gas sales in 1999 due to colder weather.
Electric retail sales increased primarily due to the warmer weather in 1998 as compared to 1997. Wholesale sales increased due to larger amounts of power available for off-system sales, an increase in the unit price of the sales and sales to KU of $11.6 million due to economic dispatch following the merger in May 1998 of LG&E Energy and KU Energy. Gas retail sales decreased from 1997 due to the warmer weather in 1998. Gas wholesale sales increased to $8.7 million in 1998 from zero in 1997 due to the implementation of LG&E's gas performance-based ratemaking mechanism. See Note 3 of LG&E's Notes to Financial Statements under Item 8.
Expenses
Fuel for electric generation and gas supply expenses comprises a large component of LG&E's total operating costs. LG&E's electric rates contain an FAC and gas rates contain a GSC, whereby increases or decreases in the cost of fuel and gas supply are reflected in base rates, subject to approval by the Kentucky Commission. In July 1999, the Kentucky Commission approved LG&E's filing on PBR resulting in the discontinuance of the FAC. In January 2000, the Kentucky Commission rescinded its approval of LG&E's PBR filing and ordered the reinstatement of the FAC. See Note 3 of LG&E's Notes to Financial Statements under Item 8 for a further discussion of the PBR and the FAC.
Fuel for electric generation increased $4.4 million (2.9%) in 1999 because of an increase in generation to support increased electric sales ($7.4 million), offset partially by a lower cost of coal burned ($3 million). Fuel expenses incurred in 1998 increased $5.2 million (3.5%) because of higher cost of coal burned ($6.6 million), partially offset by a decrease in generation ($1.4 million). The average delivered cost per ton of coal purchased was $21.49 in 1999, $22.38 in 1998, and $21.66 in 1997.
LG&E: (cont.):
Power purchased increased $119.4 million (238%) in 1999 primarily due to increased purchases to serve native load customers during the summer months and off-system sales activity. Power purchased increased $32.9 million (191%) in 1998 to support the increase in wholesale sales and increased purchases from KU of $16 million as a result of economic dispatch following the merger of the two companies in May 1998.
Gas supply expenses decreased $11.1 million (8.9%) in 1999 primarily due to a decrease in cost of net gas supply ($17.1 million), partially offset by an increase in the volume of gas delivered to the distribution system ($6 million). Gas supply expenses decreased $33 million (21%) in 1998 primarily due to a decrease in the volume of gas delivered to the distribution system. The average unit cost per Mcf of purchased gas was $2.99 in 1999, $3.05 in 1998 and $3.46 in 1997.
Operation expenses decreased $8.9 million (5.4%) in 1999 primarily due to decreased costs to operate the electric generating plants ($5.7 million) and lower administrative costs ($4.6 million). Operation expenses increased $12.8 million (8.5%) in 1998 over 1997 because of increased costs to operate electric generating plants ($6.6 million), amortization of deferred merger costs ($1.8 million), and an increase in storm damage expenses ($1.4 million).
Maintenance expenses for 1999 increased $5.3 million (10.1%) primarily due to increases in scheduled outages at the Mill Creek generating station units 3 and 4, and the Cane Run generating station units 4 and 6 ($2.4 million) and increased forced outages at Mill Creek units 1 and 4 and Cane Run unit 5 ($3.9 million). In 1998 maintenance expenses increased $5.2 million (10.9%) as compared to 1997 primarily because of an increase in scheduled outages and general repairs at the electric generating plants ($2.2 million) and an increase in storm damage expenses ($1.4 million).
Depreciation and amortization increased $4 million (4.3%) in 1999 over 1998 due to additional utility plant in service. Depreciation and amortization for 1998 were approximately the same as in 1997.
LG&E incurred a pre-tax charge in the second quarter of 1998 for costs associated with the merger of LG&E Energy and KU Energy of $32.1 million. The corresponding tax benefit of $8.5 million is recorded in other income and (deductions). The amount charged is in excess of the amount permitted to be deferred as a regulatory asset by the Kentucky Commission. See Note 2 of LG&E's Notes to Financial Statements under Item 8.
Interest charges for 1999 increased $1.6 million (4.5%) due to short term borrowings and interest on debt to associated companies ($2.5 million), partially offset by lower interest rates on variable rate debt ($.6 million). Interest charges for 1998 decreased $2.9 million (7.3%) due to the retirement of LG&E's 6.75% Series First Mortgage Bonds and lower variable interest rates. The embedded cost of long-term debt was 5.46% at December 31, 1999, and 5.57% at December 31, 1998. See Note 10 of LG&E's Notes to Financial Statements under Item 8.
Variations in income tax expenses are largely attributable to changes in pre-tax income as well as non-deductible merger expenses.
The rate of inflation may have a significant impact on LG&E's operations, its ability to control costs and the need to seek timely and adequate rate adjustments. However, relatively low rates of inflation in the past few years have moderated the impact on current operating results.
LG&E: (cont.):
LIQUIDITY AND CAPITAL RESOURCES
LG&E uses net cash generated from its operations and external financing to fund construction of plant and equipment and the payment of dividends. LG&E believes that such sources of funds will be sufficient to meet the needs of its business in the foreseeable future.
Operating Activities
Cash provided by operations was $180.5 million, $225.7 million and $185.0 million in 1999, 1998 and 1997, respectively. The 1999 decrease resulted from a net decrease in non-cash income statement items and a net decrease in net current assets, including decreases in accounts payable and accrued taxes. The 1998 increase was primarily due to an increase in current assets, including increases in accounts payable and accrued taxes.
Investing Activities
LG&E's primary use of funds continues to be for capital expenditures and the payment of dividends. Capital expenditures were $195 million, $138 million and $111 million in 1999, 1998 and 1997, respectively. LG&E expects its capital expenditures for 2000 and 2001 will total approximately $401 million which consists primarily of construction estimates associated with installation of low nitrogen oxide burner systems as described in the section titled "Environmental Matters."
Net cash used for investment activities increased by $47.2 million in 1999 compared to 1998 and increased $10 million in 1998 compared to 1997 primarily due to increased construction expenditures in both periods.
Financing Activities
Cash inflow from financing activities in 1999 was $26.7 million and cash outflows for 1998 and 1997 were $107.6 million and $64.5 million, respectively. In 1999, total debt increased by $120.1 million to $746.9 million at December 31, 1999. The increase was primarily due to funding operating expenses and construction expenditures.
As of December 1999, LG&E had committed credit facility aggregating $200.0 million with various banks. Unused capacity under these lines were approximately $90 million after considering the commercial paper support. The credit facility will expire in 2001 and management expects to renegotiate the credit facility at that time.
Future Capital Requirements
Future utility requirements may be affected in varying degrees by factors such as load growth, changes in construction expenditure levels, rate actions by regulatory agencies, new legislation, market entry of competing electric power generators, changes in environmental regulations and other regulatory requirements. LG&E anticipates to fund its requirements through additional operating cash flow, debt or an issuance of preferred cstock.
LG&E: (cont.):
LG&E's debt ratings as of February 16, 2000, were:
Moody's S&P D&P ------- --- ---
First mortgage bonds A1 A+ AA- Unsecured debt A2 A- A+ Preferred stock a2 BBB+ A Commercial paper P-1 A-1 D-1
The ratings stated above reflect the downgrades received following an order from the Kentucky Commission to reduce base rates at LG&E by $27.2 million. As of March 21, 2000, Moody's, S&P and D&P had LG&E on Credit Watch with negative implications. Based upon the downgrades received LG&E's cost of funds could increase by .05% to .12% on short-term borrowings and .10% on new long-term borrowings. These ratings reflect the views of Moody's, S&P and D&P. A security rating is not a recommendation to buy, sell or hold securities and is subject to revision or withdrawal at any time by the rating agency.
Market Risks
LG&E is exposed to market risks from changes in interest rates and commodity prices. To mitigate changes in cash flows attributable to these exposures, LG&E has entered into various derivative instruments. Derivative positions are monitored using techniques that include market value and sensitivity analysis.
Interest Rate Sensitivity
LG&E has short-term and long-term variable rate debt obligations outstanding. At December 31, 1999, the potential change in interest expense associated with a 1% change in base interest rates of LG&E's unswapped debt is estimated at $1.0 million.
Interest rate swaps are used to hedge LG&E's underlying variable rate debt obligations. These swaps hedge specific debt issuance and consistent with management's designation are accorded hedge accounting treatment.
As of December 31, 1999, LG&E had swaps with a combined notional value of $151 million. The swaps exchange floating-rate interest payments for fixed interest payments to reduce the impact of interest rate changes on LG&E's Pollution Control Bonds. As of December 31, 1999, 61% of the outstanding variable interest rate borrowings were converted to fixed interest rates through swaps. The potential loss in fair value from these positions resulting from a hypothetical 1% adverse movement in base interest rates is estimated at $2.1 million as of December 31, 1999. Changes in the market value of these swaps if held to maturity, as LG&E intends to do, will have no effect on LG&E's net income or cash flow. See Note 4 of LG&E's Notes to Financial Statements under Item 8.
Commodity Price Sensitivity
LG&E has limited exposure to market price volatility in prices of fuel and electricity, as long as cost-based regulations exist, including the FAC and GSC.
LG&E: (cont.):
YEAR 2000 COMPUTER SOFTWARE ISSUE
Result of Year 2000 Preparation
The remediation efforts of LG&E in preparing for potential Year 2000 computer problems were successful and resulted in LG&E incurring no material disruptions in services or operations of any sort. To the extent, if any, certain third parties such as interconnected utilities, key customers or suppliers still face Year 2000 disruptions due to incomplete remediation, LG&E may still retain risk related to Year 2000 issues. LG&E is not presently aware of any such situations and does not anticipate such events will have a material effect on LG&E's financial condition or results of operations.
Cost of Year 2000 Issues
LG&E's system modification costs related to the Year 2000 issue were expensed as incurred, while new system installations are being capitalized pursuant to generally accepted accounting principles. See Note 1 of LG&E's Notes to Financial Statements under Item 8. Through December 1999, LG&E incurred approximately $18.6 million in capital and operating costs in connection with the Year 2000 issue.
RATES AND REGULATION
LG&E is subject to the jurisdiction of the Kentucky Commission in virtually all matters related to electric and gas utility regulation, and as such, their accounting is subject to SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. Given LG&E's competitive position in the market and the status of regulation in the states of Kentucky LG&E has no plans or intentions to discontinue its application of SFAS No. 71. See Note 3 of LG&E's Notes to Financial Statements under Item 8.
Environmental Cost Recovery
In May 1995, LG&E implemented an ECR surcharge. The Kentucky Commission's order approving the surcharge as well as the constitutionality of the surcharge was challenged by certain intervenors in Franklin Circuit Court. Decisions of the Circuit Court and the Kentucky Court of Appeals in July 1995 and December 1997, respectively, upheld the constitutionality of the ECR statute but differed on a claim of retroactive recovery of certain amounts. Based on these decisions, the Kentucky Commission ordered that certain surcharge revenues collected by LG&E be subject to refund pending final determination of all appeals.
In December 1998, the Kentucky Supreme Court rendered an opinion upholding the constitutionality of the surcharge statute but denied recovery of costs associated with pre-1993 environmental projects through the ECR. The court remanded the case to the Kentucky Commission to determine amounts to be refunded for revenues collected for such pre-1993 environmental projects. Accordingly, LG&E recorded a provision for rate refunds of $4.5 million in December 1998.
The parties to the proceedings reached a settlement agreement that was approved in a Final Order issued by the Kentucky Commission in August 1999. This Final Order resulted in the additional accrual of approximately $0.6 million to what had been recorded in December 1998. The refund is being applied to customers' bills during the twelve-month period beginning October 1999.
LG&E: (cont.):
Future Rate Regulation
In October 1998, LG&E filed an application with the Kentucky Commission for approval of a new method of determining electric rates that sought to provide financial incentives for LG&E to further reduce customers' rates. The filing was made pursuant to the September 1997 Kentucky Commission order approving the merger of LG&E Energy and KU Energy, wherein the Kentucky Commission directed LG&E to indicate whether they desired to remain under traditional rate of return regulation or commence non-traditional regulation. The proposed ratemaking method, known as PBR, included financial incentives for LG&E to reduce fuel costs and increase generating efficiency, and to share any resulting savings with customers. Additionally, the PBR proposal provided for financial penalties and rewards to assure continued high quality service and reliability.
In April 1999, LG&E filed a joint agreement with KU and the Kentucky Attorney General to adopt the PBR plan subject to certain amendments. The amended filing included requested Kentucky Commission approval of a five-year rate reduction plan which proposed to reduce the electric rates of LG&E by $9.4 million in the first year (beginning July 1999), and by $3.8 million annually through June 2004. The proposed amended plan also included establishment of a $2.8 million program for low-income customer assistance as well as extension for one additional year of both the rate cap proposal and merger savings surcredit established in the original merger plan of LG&E and KU. Under the rate cap proposal, LG&E agreed, in the absence of extraordinary circumstances, not to increase base electric rates for five years following the merger and LG&E also agreed to refrain from filing for an increase in natural gas rates through June 2004.
In April 1999, the Kentucky Commission issued initial orders implementing the amended PBR plan, effective July 1999, and subject to modification. The Kentucky Commission also consolidated into the continuing PBR proceedings an earlier March 1999, rate complaint by a group of industrial intervenors, KIUC, in which KIUC requested significant reductions in electric rates. Hearings were conducted before the Kentucky Commission on LG&E's amended PBR plan and the KIUC rate reduction petitions in August and September 1999. Legal briefs of the parties were filed with the Kentucky Commission in October 1999. KIUC's position called for annual revenue reductions for LG&E of $69.6 million.
In January 2000, the Kentucky Commission issued Orders for LG&E in the subject cases. The Kentucky Commission ruled that LG&E should reduce base rates by $27.2 million effective with bills rendered beginning March 1, 2000. The Kentucky Commission eliminated LG&E's proposal to operate under its PBR plan and reinstated the fuel adjustment clause mechanism effective March 1, 2000. The Kentucky Commission offered LG&E the opportunity to operate under an ESM for the next three years. Under this mechanism, incremental annual earnings resulting in a rate of return either above or below a range of 10.5% to 12.5% would be shared 60% with shareholders and 40% with ratepayers.
Later in January 2000, LG&E filed motions for correction to the January 2000 orders for computational and other errors made in the Kentucky Commission's orders which produced overstatements in the base rate reductions to LG&E of $1.1 million. LG&E also filed motions for reconsideration with the Kentucky Commission on a number of items in the case in late January. Certain intervening parties in the proceedings have also filed motions for reconsideration asserting, among other things, that the Kentucky Commission understated the amount of base rate reductions. In February 2000, LG&E accepted the Kentucky Commission's proposed ESM and filed an ESM tariff which contained detailed provisions for operation of the ESM rates. Management cannot predict final outcome of these matters before the Kentucky Commission or the timing in which resolution of these matters will ultimately be reached.
LG&E: (cont.):
Other Rate Matters
LG&E's rates contain a DSM provision. The provision includes a rate mechanism that provides concurrent recovery of DSM costs and provides an incentive for implementing DSM programs. This program had allowed LG&E to recover revenues from lost sales associated with the DSM program (decoupling), but in 1998, LG&E and customer interest groups requested an end to the decoupling rate mechanism. In September 1998, the Kentucky Commission accepted LG&E's modified tariff discontinuing the decoupling mechanism effective as of June 1, 1998.
Since October 1997, LG&E has implemented an experimental performance-based ratemaking mechanism related to gas procurement activities and off-system gas sales only. During the three-year test period beginning October 1997, rate adjustments related to this mechanism will be determined for each 12-month period beginning November 1 and ending October 31. During the first two years of the mechanism ended October 31, 1999 and 1998, LG&E recorded $2.2 million and $3.5 million, respectively, for its share of reduced gas costs. These amounts are billed to customers through the gas supply clause.
Prior to implementation of the PBR in July 1999, and following its termination in March 2000, LG&E employed an FAC mechanism, which under Kentucky law allowed LG&E to recover from customers, the actual fuel costs associated with retail electric sales. In February 1999, LG&E received orders from the Kentucky Commission requiring a refund to retail electric customers of approximately $3.9 million resulting from reviews of the FAC from November 1994 through April 1998, of which $1.9 million was refunded in April 1999 for the period beginning November 1994 and ending October 1996. The orders changed LG&E's method of computing fuel costs associated with electric line losses on off-system sales appropriate for recovery through the FAC. LG&E requested that the Kentucky Commission grant rehearing on the February orders, and further requested that the Kentucky Commission stay the refund requirement until it could rule on the rehearing request. The Kentucky Commission granted the request for a stay, and in March 1999 granted rehearing on the appropriate line loss factor associated with off-system sales for the 18-month period ended April 1998. The Kentucky Commission also granted rehearing on the KIUC's request for rehearing on the Kentucky Commission's determination that it lacked authority to require the utilities to pay interest on the refund amounts. The Kentucky Commission conducted a hearing on the rehearing issues and issued a final ruling in December 1999. The Kentucky Commission agreed with LG&E 's position on the appropriate loss factor to use in the FAC computation and reduced the refund level for the 18-month period under review to approximately $800,000. LG&E enacted the refund with billings in the month of January 2000. LG&E and KIUC have each filed separate appeals from the Kentucky Commission's February 1999 orders with the Franklin Circuit Court. A decision on the appeals by the Court is expected in 2000.
LG&E intends to file before the end of the first quarter an application with the Kentucky Commission for authority to increase its natural gas rates in order to recoup higher costs for providing natural gas distribution services. LG&E expects implementation before the end of 2000.
Kentucky PSC Administrative Case for Affiliate Transactions
In December 1997, the Kentucky Commission opened Administrative Case No. 369 to consider Kentucky Commission policy regarding cost allocations, affiliate transactions and codes of conduct governing the relationship between utilities and their non-utility operations and affiliates. The Kentucky Commission intends to address two major areas in the proceedings: the tools and conditions needed to prevent cost shifting and cross-subsidization between regulated and non-utility operations; and whether a code of conduct should be established to assure that non-utility segments of the holding company are not engaged in practices that could
result in unfair competition caused by cost shifting from the non-utility affiliate to the utility. In September 1998, the Kentucky Commission issued a draft code of conduct and cost allocation guidelines. In January 1999, LG&E, as well as all parties to the proceeding, filed comments on the Kentucky Commission draft proposals. In December 1999, the Kentucky Commission issued guidelines on cost allocation and held a hearing in January 2000, on the draft code of conduct. Management does not expect the ultimate resolution of this matter to have a material adverse effect on LG&E's financial position or results of operations.
Environmental Matters
The Act imposed stringent new SO2 and NOx emission limits on electric generating units. LG&E previously had installed scrubbers on all of its generating units. LG&E's strategy for Phase II, commencing January 1, 2000, is to use accumulated emissions allowances to delay additional capital expenditures and may also include fuel switching or the installation of additional scrubbers. LG&E met the NOx emission requirements of the Act through installation of low-NOx burner systems. LG&E's compliance plans are subject to many factors including developments in the emission allowance and fuel markets, future regulatory and legislative initiatives, and advances in clean air control technology. LG&E will continue to monitor these developments to ensure that its environmental obligations are met in the most efficient and cost-effective manner.
In September 1998, the EPA announced its final "NOx SIP call" rule requiring significant additional reductions in NOx emissions by May 2003, in order to mitigate alleged ozone transport to the Northeast. While each of the 22 states covered by the rule is free to allocate its assigned NOx reductions among various emissions sectors as it deems appropriate, the regulation may ultimately require electric generating units to reduce their NOx emissions to 0.15 lb./Mmbtu - an 85% reduction from 1990 levels. In related proceedings in response to petitions filed by various Northeast states, in December 1999, EPA issued a final rule directing similar NOx reductions from a number of specifically named electric generating units including all LG&E stations. Several states, various labor and industry groups, and individual companies have appealed both EPA rulings to the U.S. Court of Appeals for the Washington D.C. Circuit. Management is currently unable to determine the outcome or exact impact of this matter until such time as the courts rule on the pending legal challenges and the states implement the final regulatory mandate. However, if the 0.15 lb. target is ultimately imposed, LG&E will be required to incur significant capital expenditures and increased operation and maintenance costs for additional controls.
Subject to further study, analysis, and the outcome of pending litigation against the EPA, LG&E estimates that it may incur approximate capital costs for NOx compliance ranging from $65 million to reduce emissions to the level of .25 lb./Mmbtu (Commonwealth of Kentucky's proposed NOx compliance level) to $165 million to reduce emissions to the level of .15 lb./Mmbtu (current EPA regulations). These costs would generally be incurred beginning in 2000. LG&E believes its costs in this regard to be comparable to those of similarly situated utilities with like generation assets. LG&E anticipates that such capital and operating costs are the type of costs that are eligible for recovery from customers under their environmental surcharge mechanisms and believe that a significant portion of such costs could be recovered. However, Kentucky Commission approval is necessary and there can be no guarantee of recovery.
LG&E is also addressing other air quality issues. First, LG&E is monitoring the status of EPA's revised NAAQS for ozone and particulate matter. In May 1999, the Washington D.C. Circuit remanded the final rule and directed EPA to undertake additional rulemaking efforts. LG&E continues to monitor EPA actions to challenge that ruling. Second, LG&E was notified by regulatory agencies that the Cane Run Station may be the source of a potential exceedance of the NAAQS that could require LG&E to incur additional capital expenditures or accept certain emissions limitations. After reviewing additional modeling information submitted by
LG&E: (cont.):
LG&E, in January 2000, EPA concluded that the Cane Run Station does not contribute to any potential NAAQS exceedance and that no further action is required from LG&E. Third, LG&E is working with regulatory authorities to review the effectiveness of remedial measures aimed at controlling particulate emissions from its Mill Creek Station. LG&E previously settled a number of property damage claims from adjacent residents and completed significant plant modifications as part of its ongoing capital construction program.
LG&E owns or formerly owned three properties which contained past MGP operations. Various contaminants are typically found at such former MGP sites and environmental remediation measures are frequently required. LG&E has reached agreements for other parties to assume cleanup responsibility for two other sites it formerly owned. In addition, LG&E recently reached an agreement with the Kentucky Division of Waste Management with respect to a third LG&E-owned site in which LG&E committed to impose certain property restrictions and conduct additional monitoring in lieu of a cleanup. Based on currently available information, management estimates that it will incur additional MGP costs of less than $500,000. Accordingly, an accrual of $500,000 has been recorded in the accompanying financial statements.
See Note 12 of LG&E's Notes to Financial Statements under Item 8 for an additional discussion of environmental issues.
FUTURE OUTLOOK
Competition and Customer Choice
LG&E has moved aggressively over the past decade to be positioned for, and to help promote, the energy industry's shift to customer choice and a competitive market for energy services. Specifically, LG&E has taken many steps to prepare for the expected increase in competition in its business, including support for performance-based ratemaking structures, aggressive cost reduction activities; strategic acquisitions, dispositions and growth initiatives; write-offs of previously deferred expenses; an increase in focus on commercial and industrial customers; an increase in employee training; and necessary corporate and business unit realignments. LG&E continues to be active in the national debate surrounding the restructuring of the energy industry and the move toward a competitive, market-based environment. LG&E has urged Congress to set a specific date for a complete transition to a competitive market, one that will quickly and efficiently bring the benefits associated with customer choice. LG&E has previously advocated the implementation of this transition by January 1, 2001, and now recommends adoption of federal legislation specifying a date certain and appropriate transition regulations implementing deregulation.
In December 1997, the Kentucky Commission issued a set of principles which was intended to serve as its guide in consideration of issues relating to industry restructuring. Among the issues addressed by these principles are: consumer protection and benefit, system reliability, universal service, environmental responsibility, cost allocation, stranded costs and codes of conduct. During 1998, the Kentucky Commission and a task force of the Kentucky General Assembly had each initiated proceedings, including meetings with representatives of utilities, consumers, state agencies and other groups in Kentucky, to discuss the possible structure and effects of energy industry restructuring in Kentucky.
In November 1999, the task force issued a report to the Governor of Kentucky and a legislative agency recommending no general electric industry restructuring actions during the 2000 legislative session.
Thus, at the time of this report, neither the Kentucky General Assembly nor the Kentucky Commission has adopted or approved a plan or timetable for retail electric industry competition in Kentucky. The nature or
LG&E: (cont.):
timing of the ultimate legislative or regulatory actions regarding industry restructuring and their impact on LG&E, which may be significant, cannot currently be predicted.
KU
GENERAL
The following discussion and analysis by management focuses on those factors that had a material effect on KU's financial results of operations and financial condition during 1999, 1998, and 1997 and should be read in connection with the financial statements and notes thereto.
Some of the following discussion may contain forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words "anticipate," "expect," "estimate," "objective," "possible," "potential" and similar expressions. Actual results may vary materially. Factors that could cause actual results to differ materially include: general economic conditions; business and competitive conditions in the energy industry; changes in federal or state legislation; unusual weather; actions by state or federal regulatory agencies; and other factors described from time to time in KU's reports to the Securities and Exchange Commission, and Exhibit No. 99.01 to LG&E Energy's annual report on Form 10-K for the year ended December 31, 1998.
MERGER
Effective May 4, 1998, following the receipt of all required state and federal regulatory approvals, LG&E Energy and KU Energy merged, with LG&E Energy as the surviving corporation. The outstanding preferred stock of KU, a subsidiary of KU Energy before the merger, was not affected by the merger. See Note 2 of KU's Notes to Financial Statements under Item 8.
RESULTS OF OPERATIONS
Net Income
KU's net income increased $33.8 million for 1999, as compared to 1998, primarily due to non-recurring charges in 1998 for merger-related expenses and environmental cost recovery refund of $21.5 million and $12.9 million, after tax, respectively, offset by net rate refunds incurred in 1999 of $3.5 million, after tax. Excluding these non-recurring charges, net income increased $2.9 million. This increase was due to higher retail electric and off-system sales results, and lower operation and maintenance costs, offset by higher purchased power expenses for the year.
KU's net income decreased $12.9 million for 1998 as compared to 1997, primarily due to non-recurring charges for merger-related expenses and environmental cost recovery refund of $21.5 million and $12.9 million, after tax, respectively. Excluding these non-recurring charges, net income increased $21.5 million. The increase is mainly due to higher residential sales, commercial sales, industrial sales and sales for resale caused by the warmer weather and increased marketing efforts.
Revenues
A comparison of operating revenues for the years 1999 and 1998, excluding the provision for rate refunds for the ECR refund and the FAC refund previously recovered from customers, $5.9 million in 1999 and $21.5
KU (cont.):
million in 1998, with the immediately preceding year reflects both increases and decreases which have been segregated by the following principal causes (in thousands of $):
Increase (Decrease) From Prior Period Cause 1999 1998 ---- ----
Retail sales: Fuel clause adjustments, etc $ (1,744) $ 1,158 Merger surcredit (4,123) (4,035) Environmental cost recovery surcharge (1,977) (547) Performance based rate reduction (5,558) -- Variation in sales volumes 19,303 25,841 --------- --------- Total retail sales 5,901 22,417 Wholesale sales 106,160 90,253 Other (465) 2,507 --------- --------- Total $ 111,596 $ 115,177 ========= =========
The increase in sales for resale in 1999 was primarily due to more aggressive marketing efforts.
Retail sales increased in 1998 due to increases in residential and commercial sales primarily attributable to warmer weather experienced in the second and third quarters. The increase in sales for resale was primarily due to more aggressive marketing efforts, increases in the unit price of the sales, efficiencies achieved from coordinated dispatch of a larger available pool of generation following completion of the merger, and sales to LG&E of $16 million due to economic dispatch following the merger in May 1998 of LG&E Energy and KU Energy.
Provision for rate refund reflects a net charge in revenues during 1999 of $5.9 million for the refund of costs previously recovered from customers under the fuel adjustment clause and the environmental cost recovery mechanism. Provision for rate refund reflects a charge in revenues during 1998 of $21.5 million for the refund of environmental costs previously recovered from customers. See Note 3 of KU's Notes to Financial Statements under Item 8.
Expenses
Fuel for electric generation comprises a large component of KU's total operating expenses. KU's Kentucky jurisdictional electric rates were subject to a FAC whereby increases or decreases would be reflected in retail rates, subject to the approval of the Kentucky Commission. Effective July 2, 1999 the FAC was discontinued and replaced with an amended electric PBR. In January 2000, the Kentucky Commission rescinded its approval of KU's PBR filing and ordered the reinstatement of the FAC. See Note 3 of KU's Notes to Financial Statements under Item 8 for a further discussion of the PBR and the FAC. KU's wholesale and Virginia jurisdictional electric rates contain a fuel adjustment clause whereby increases or decreases in the cost of fuel are reflected in rates, subject to the approval of the Virginia Commission and the FERC.
Fuel for electric generation increased $2.5 million (1%) in 1999 because of an increase in generation ($5.1 million), partially offset by a decrease in the cost of coal burned ($2.6 million). Fuel for electric generation increased $29 million (13%) in 1998 because of an increase in generation ($26.2 million) and an increase in the cost of coal burned ($2.8 million). KU's average delivered cost per ton of coal purchased was $26.65 in 1999, $26.97 in 1998 and $27.97 in 1997.
KU (cont.):
Power purchased increased $115.7 million in 1999 primarily to support the aforementioned sales for resale. Power purchased expense increased $54 million (75%) in 1998 because of a 67% increase in megawatt-hour purchases which was primarily attributable to increased marketing efforts and purchases from LG&E of $11.6 million as a result of economic dispatch following the merger of the two companies in May 1998.
Maintenance expense decreased $6.3 million (10%) in 1999 due to decreases in maintenance at the steam generating plants and the transmission and distribution systems. Maintenance for 1998 was flat as compared to 1997.
Depreciation and amortization increased $3.3 million (3.8%) in 1999 and $2.5 million (1.5%) in 1998 because of additional utility plant in service in both years.
Merger costs to achieve reflects the one-time charge during 1998 of $21.7 million (the corresponding tax benefit of $.2 million is recorded in other income and (deductions) for merger related expenses as discussed in Note 2 of KU's Notes to Financial Statements under Item 8).
KU's embedded cost of long-term debt was 7.00% at December 31, 1999, and 6.99% at December 31, 1998. See Note 10 of KU's Notes to Financial Statements under Item 8.
Variations in income tax expense are largely attributable to changes in pre-tax income as well as non-deductible merger expenses.
The rate of inflation may have a significant impact on KU's utility operations, its ability to control costs and the need to seek timely and adequate rate adjustments. However, relatively low rates of inflation in the past few years have moderated the impact on current operating results.
LIQUIDITY AND CAPITAL RESOURCES
KU uses net cash generated from its operations and external financing to fund construction of plant and equipment and the payment of dividends. KU believes that such sources of funds will be sufficient to meet the needs of its business in the foreseeable future.
Operating Activities
Cash provided by operations was $204.2 million, $239.4 million and $178.9 million in 1999, 1998 and 1997, respectively. The 1999 decrease of resulted from an increase in net income and a net decrease in net current assets, including decreases in accounts receivable, accounts payable, accrued taxes and provision for rate refunds. The 1998 increase was primarily due to an increase in current assets, including increases in accounts payable, accrued taxes and provision for rate refunds, partially offset by an increase in accounts receivable.
Investing Activities
KU's primary use of funds continues to be for capital expenditures and the payment of dividends. Capital expenditures were $181 million, $92 million and $94 million in 1999, 1998 and 1997, respectively. The $89 million increase in 1999 capital expenditures was primarily due to the purchase of a 62% interest in the two combustion turbines. KU expects its capital expenditures for 2000 and 2001 will total approximately $324 million which consists primarily of construction costs associated with installation of low nitrogen oxide burner systems as described in the section titled "Environmental Matters."
KU (cont.):
Net cash used for investment activities increased by $89.3 million in 1999 compared to 1998 and increased $2.1 million in 1998 compared to 1997 primarily due to increased construction expenditures in both periods.
Future Capital Requirements
Future utility requirements may be affected in varying degrees by factors such as load growth, changes in construction expenditure levels, rate actions by regulatory agencies, new legislation, market entry of competing electric power generators, changes in environmental regulations and other regulatory requirements. KU anticipates to fund its requirements through additional operating cash flow, debt or an issuance of preferred stock.
Financing Activities
Cash outflows from financing activities were $75.2 million, $94.0 million and $89.4 million, in 1999, 1998 and 1997, respectively. In 1999, there was no increase in total debt, balance as of December 31, 1999 remained $546.3 million.
KU's debt ratings as of February 16, 2000, were:
Moody's S&P D&P ------- --- ---
First mortgage bonds A1 A+ AA- Preferred stock a2 BBB+ A Commercial paper P-1 A-1 D-1
The ratings stated above reflect the downgrades received following the PBR-related order from the Kentucky Commission to reduce base rates at KU by $36.5 million. As of March 21, 2000, Moody's, S&P and D&P had KU on Credit Watch with negative implications. Based upon the downgrades received KU's cost of funds could increase by .05% to .12% on short-term borrowings and .10% on new long-term borrowings. These ratings reflect the views of Moody's, S&P and D&P. A security rating is not a recommendation to buy, sell or hold securities and is subject to revision or withdrawal at any time by the rating agency.
Market Risks
KU is exposed to market risks from changes in interest rates and commodity prices. To mitigate changes in cash flows attributable to these exposures, KU has entered into various derivative instruments. Derivative positions are monitored using techniques that include market value and sensitivity analysis.
Interest Rate Sensitivity
KU has long-term variable rate debt obligations outstanding. At December 31, 1999, the potential change in interest expense associated with a 1% change in base interest rates of KU's unswapped debt is estimated at $1.0 million. These swaps hedge specific debt issuance and consistent with management's designation are accorded hedge accounting treatment.
As of December 31, 1999, KU has a swap with a notional value of $53 million. The swaps exchange fixed-rate interest payments for floating interest payments on KU's 7.92% Series P Pollution Control Bond. The potential loss in fair value from these positions resulting from a hypothetical 1% adverse movement in base interest rates
KU (cont.):
is estimated at $3.7 million as of December 31, 1999. Changes in the market value of these swaps if held to maturity, as KU intends to do, will have no effect on KU's net income or cash flow. See Note 4 of KU's Notes to Financial Statements under Item 8.
Commodity Price Sensitivity
KU has limited exposure to market price volatility in prices of fuel and electricity, as long as cost-based regulations exist, including the FAC.
YEAR 2000 COMPUTER SOFTWARE ISSUE
Result of Year 2000 Preparation
The remediation efforts of KU in preparing for potential Year 2000 computer problems were successful and resulted in KU incurring no material disruptions in services or operations of any sort. To the extent, if any, certain third parties such as interconnected utilities, key customers or suppliers still face Year 2000 disruptions due to incomplete remediation, KU may still retain risk related to Year 2000 issues. KU is not presently aware of any such situations and does not anticipate such events will have a material effect on KU's financial condition or results of operations.
Cost of Year 2000 Issues
KU's system modification costs related to the Year 2000 issue were expensed as incurred, while new system installations are being capitalized pursuant to generally accepted accounting principles. See Note 1 of KU's Notes to Financial Statements under Item 8. Through December 1999, KU incurred approximately $5.1 million in capital and operating costs in connection with the Year 2000 issue.
RATES AND REGULATION
KU is subject to the jurisdiction of the Kentucky Commission, the Virginia Commission and FERC in virtually all matters related to electric utility regulation, and as such, its accounting is subject to SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. Given KU's competitive position in the market and the status of regulation in the states of Kentucky and Virginia, KU no plans or intentions to discontinue its application of SFAS No. 71. See Note 6 of LG&E Energy's Notes to Financial Statements under Item 8.
Environmental Cost Recovery
In August 1994, KU implemented an ECR surcharge. The Kentucky Commission's order approving the surcharge as well as the constitutionality of the surcharge was challenged by certain intervenors in Franklin Circuit Court. Decisions of the Circuit Court and the Kentucky Court of Appeals in July 1995 and December 1997, respectively, upheld the constitutionality of the ECR statute but differed on a claim of retroactive recovery of certain amounts. Based on these decisions, the Kentucky Commission ordered that certain surcharge revenues collected by KU be subject to refund pending final determination of all appeals.
In December 1998, the Kentucky Supreme Court rendered an opinion upholding the constitutionality of the surcharge statute but denied recovery of costs associated with pre-1993 environmental projects through the ECR. The court remanded the case to the Kentucky Commission to determine amounts to be refunded for revenues collected for such pre-1993 environmental projects. Accordingly, KU recorded a provision for rate
KU (cont.):
refund of $21.5 million in December 1998.
The parties to the proceedings reached a settlement agreement that was approved in a Final Order issued by the Kentucky Commission in August 1999. This Final Order resulted in a reduction of approximately $1.5 million to the accrual that had been recorded in December 1998. The refund is being applied to customers' bills during the twelve-month period beginning October 1999.
Future Rate Regulation
In October 1998, KU filed an application with the Kentucky Commission for approval of a new method of determining electric rates that sought to provide financial incentives for KU to further reduce customers' rates. The filing was made pursuant to the September 1997 Kentucky Commission order approving the merger of LG&E Energy and KU Energy, wherein the Kentucky Commission directed KU to indicate whether they desired to remain under traditional rate of return regulation or commence non-traditional regulation. The proposed ratemaking method, known as PBR, included financial incentives for KU to reduce fuel costs and increase generating efficiency, and to share any resulting savings with customers. Additionally, the PBR proposal provided for financial penalties and rewards to assure continued high quality service and reliability.
In April 1999, KU filed a joint agreement with LG&E and the Kentucky Attorney General to adopt the PBR plan subject to certain amendments. The amended filing included requested Kentucky Commission approval of a five-year rate reduction plan which proposed to reduce the electric rates of KU by $10.6 million in the first year (beginning July 1999), and by $4.2 million annually through June 2004. The proposed amended plan also included establishment of a $3.2 million program for low-income customer assistance as well as extension for one additional year of both the rate cap proposal and merger savings surcredit established in the original merger plan of LG&E Energy and KU Energy. Under the rate cap proposal, KU agreed, in the absence of extraordinary circumstances, not to increase base electric rates for five years following the merger through June 2004.
In April 1999, the Kentucky Commission issued initial orders implementing the amended PBR plan, effective July 1999, and subject to modification. The Kentucky Commission also consolidated into the continuing PBR proceedings an earlier March 1999, rate complaint by a group of industrial intervenors, KIUC, in which KIUC requested significant reductions in electric rates. Hearings were conducted before the Kentucky Commission on KU's amended PBR plans and the KIUC rate reduction petitions in August and September 1999. Legal briefs of the parties were filed with the Kentucky Commission in October 1999. KIUC's position called for annual revenue reductions for KU of $61.5 million.
In January 2000, the Kentucky Commission issued Orders for KU in the subject cases. The Kentucky Commission ruled that KU should reduce base rates by $36.5 million effective with bills rendered beginning March 1, 2000. The Kentucky Commission eliminated KU's proposal to operate under its PBR plan and reinstated the FAC mechanism effective March 1, 2000. The Kentucky Commission offered KU the opportunity to operate under an ESM for the next three years. Under this mechanism, incremental annual earnings for KU resulting in a rate of return either above or below a range of 10.5% to 12.5% would be shared 60% with shareholders and 40% with ratepayers.
Later in January 2000, KU filed motions for correction to the January 2000 orders for computational and other errors made in the Kentucky Commission's orders which produced overstatements in the base rate reductions to KU of $7.7 million. KU also filed motions for reconsideration with the Kentucky Commission on a number of items in the case in late January. Certain intervening parties in the proceedings have also filed motions for reconsideration asserting, among other things, that the Kentucky Commission understated the amount of base
KU (cont.):
rate reductions. In February 2000, KU accepted the Kentucky Commission's opportunity to use an ESM by filing an ESM tariff which contains the provisions operating under such mechanism. Management cannot predict final outcome of these matters before the Kentucky Commission or the timing in which resolution of these matters will ultimately be reached.
Other Rate Matters
Prior to implementation of the PBR in July 1999, and following its termination in March 2000, KU employed an FAC mechanism, which under Kentucky law allowed the utilities to recover from customers the actual fuel costs associated with retail electric sales.
In July 1999, the Kentucky Commission issued a series of orders requiring KU to refund approximately $10.1 million resulting from reviews of the FAC from November 1994 to October 1998. The orders changed KU's method of computing fuel costs associated with electric line losses on off-system sales appropriate for recovery through the FAC, and KU's method for computing system line losses for the purpose of calculating the system sales component of the FAC charge. At KU's request, in July 1999, the Kentucky Commission stayed the refund requirement pending the Kentucky Commission's final determination of any rehearing request that KU may file. In August 1999, KU filed its request for rehearing of the July orders.
In August 1999, the Kentucky Commission issued a Final Order in the KU proceedings, agreeing, in part, with KU's arguments outlined in its Petition for Rehearing. While the Kentucky Commission confirmed that KU should change its method of computing the fuel costs associated with electric line losses, it agreed with KU that the line loss percentage should be based on KU's actual line losses incurred in making off-system sales rather than the percentage used in its Open Access Transmission Tariff. The Kentucky Commission also upheld its previous ruling concerning the computation of system line losses in the calculation of the FAC. The net effect of the Kentucky Commission's Final Order was to reduce the refund obligation to $5.8 million from the original Order amount of $10.1 million. In August 1999, KU recorded its estimated share of anticipated FAC refunds of $7.7 million. KU began implementing the refund in October and will continue the refund through September 2000. Both KU and the KIUC have appealed the Order to the Franklin Circuit Court. A decision is not expected on the appeal until later in 2000.
Kentucky PSC Administrative Case for Affiliate Transactions
In December 1997, the Kentucky Commission opened Administrative Case No. 369 to consider Kentucky Commission policy regarding cost allocations, affiliate transactions and codes of conduct governing the relationship between utilities and their non-utility operations and affiliates. The Kentucky Commission intends to address two major areas in the proceedings: the tools and conditions needed to prevent cost shifting and cross-subsidization between regulated and non-utility operations; and whether a code of conduct should be established to assure that non-utility segments of the holding company are not engaged in practices that could result in unfair competition caused by cost shifting from the non-utility affiliate to the utility. In September 1998, the Kentucky Commission issued a draft code of conduct and cost allocation guidelines. In January 1999, KU, as well as all parties to the proceeding, filed comments on the Kentucky Commission draft proposals. In December 1999, the Kentucky Commission issued guidelines on cost allocation and held a hearing in January 2000, on the draft code of conduct. Management does not expect the ultimate resolution of this matter to have a material adverse effect on KU's financial position or results of operations.
KU (cont.):
Environmental Matters
The Act imposed stringent new SO2 and NOx emission limits on electric generating units. KU met its Phase I SO2 requirements primarily through installation of a scrubber on Ghent Unit 1. KU's strategy for Phase II, commencing January 1, 2000, is to use accumulated emissions allowances to delay additional capital expenditures and may also include fuel switching or the installation of additional scrubbers. KU met the NOx emission requirements of the Act through installation of low-NOx burner systems. KU's compliance plans are subject to many factors including developments in the emission allowance and fuel markets, future regulatory and legislative initiatives, and advances in clean air control technology. KU will continue to monitor these developments to ensure that its environmental obligations are met in the most efficient and cost-effective manner.
In September 1998, the EPA announced its final "NOx SIP call" rule requiring significant additional reductions in NOx emissions by May 2003, in order to mitigate alleged ozone transport to the Northeast. While each of the 22 states covered by the rule is free to allocate its assigned NOx reductions among various emissions sectors as it deems appropriate, the regulation may ultimately require electric generating units to reduce their NOx emissions to 0.15 lb./Mmbtu - an 85% reduction from 1990 levels. In related proceedings in response to petitions filed by various Northeast states, in December 1999, EPA issued a final rule directing similar NOx reductions from a number of specifically named electric generating units including all KU stations in the eastern half of Kentucky. Several states, various labor and industry groups, and individual companies have appealed both EPA rulings to the U.S. Court of Appeals for the Washington D.C. Circuit. Management is currently unable to determine the outcome or exact impact of this matter until such time as the courts rule on the pending legal challenges and the states implement the final regulatory mandate. However, if the 0.15 lb. target is ultimately imposed, KU will be required to incur significant capital expenditures and increased operation and maintenance costs for additional controls.
Subject to further study, analysis, and the outcome of pending litigation against the EPA, KU estimates that it may incur capital costs for NOx compliance ranging from $126 million to reduce emissions to the level of .25 lb./Mmbtu (Commonwealth of Kentucky's proposed NOx compliance level) to $168 million to reduce emissions to the level of .15 lb./Mmbtu (current EPA regulations). These costs would generally be incurred beginning in 2000. KU believes its costs in this regard to be comparable to those of similarly situated utilities with like generation assets. KU anticipates that such capital and operating costs are the type of costs that are eligible for recovery from customers under its environmental surcharge mechanisms and believe that a significant portion of such costs could be recovered. However, Kentucky Commission approval is necessary and there can be no guarantee of recovery.
KU owns or formerly owned several properties which contained past MGP operations. Various contaminants are typically found at such former MGP sites and environmental remediation measures are frequently required. KU has completed the cleanup of a site owned by KU. With respect to other former MGP sites no longer owned by KU, KU is unable to determine what, if any, additional exposure or liability it may have as it lacks complete information on current site conditions.
In October 1999, approximately 38,000 gallons of diesel fuel leaked from a cracked valve in an underground pipeline at KU's E.W. Brown Station. Under the oversight of EPA and state officials, KU commenced immediate spill containment and recovery measures which prevented the spill from reaching the Kentucky River. KU ultimately recovered approximately 34,000 gallons of diesel fuel. In November 1999, the Kentucky Division of Water issued a notice of violation for the incident. KU is currently negotiating with the state in an effort to reach a complete resolution of this matter. To date KU has incurred costs of approximately $1 million.
KU (cont.):
The Company does not expect to incur any material additional amounts.
KU is monitoring the status of EPA's revised NAAQS for ozone and particulate matter. In May 1999, the Washington D.C. Circuit remanded the final rule and directed EPA to undertake additional rulemaking efforts. KU continues to monitor EPA actions to challenge that ruling.
See Note 11 of KU's Notes to Financial Statements under Item 8 for an additional discussion of environmental issues.
FUTURE OUTLOOK
Competition and Customer Choice
LG&E Energy has moved aggressively over the past decade to be positioned for, and to help promote the energy industry's shift to customer choice and a competitive market for energy services. Specifically, LG&E Energy has taken many steps to prepare for the expected increase in competition in its business, including support for PBR structures, aggressive cost reduction activities; strategic acquisitions, dispositions and growth initiatives; write-offs of previously deferred expenses; an increase in focus on commercial and industrial customers; an increase in employee training; and necessary corporate and business unit realignments. LG&E Energy continues to be active in the national debate surrounding the restructuring of the energy industry and the move toward a competitive, market-based environment. LG&E Energy has urged Congress to set a specific date for a complete transition to a competitive market, one that will quickly and efficiently bring the benefits associated with customer choice. LG&E Energy has previously advocated the implementation of this transition by January 1, 2001, and now recommends adoption of federal legislation specifying a date certain and appropriate transition regulations implementing deregulation.
In December 1997, the Kentucky Commission issued a set of principles which was intended to serve as its guide in consideration of issues relating to industry restructuring. Among the issues addressed by these principles are: consumer protection and benefit, system reliability, universal service, environmental responsibility, cost allocation, stranded costs and codes of conduct. During 1998, the Kentucky Commission and a task force of the Kentucky General Assembly each initiated proceedings, including meetings with representatives of utilities, consumers, state agencies and other groups in Kentucky, to discuss the possible structure and effects of energy industry restructuring in Kentucky.
In November 1999, the task force issued a report to the Governor of Kentucky and a legislative agency recommending no general electric industry restructuring actions during the 2000 legislative session.
Thus, at the time of this report, neither the Kentucky General Assembly nor the Kentucky Commission has adopted or approved a plan or timetable for retail electric industry competition in Kentucky. The nature or timing of the ultimate legislative or regulatory actions regarding industry restructuring and their impact on KU, which may be significant, cannot currently be predicted.
ITEM 7A.
ITEM 7A. Quantitative and Qualitative Disclosure About Market Risk.
See LG&E Energy's, LG&E's and KU's Management's Discussion and Analysis of Results of Operations and Financial Condition, Market Risks, under Item 7.
ITEM 8.
ITEM 8. Financial Statements and Supplementary Data.
LG&E Energy Corp. and Subsidiaries Consolidated Statements of Income (Thousands of $ Except Per Share Data)
The accompanying notes are an integral part of these consolidated financial statements.
LG&E Energy Corp. and Subsidiaries Consolidated Statements of Income (cont.) (Thousands of $ Except Per Share Data)
Consolidated Statements of Comprehensive Income (Thousands of $)
Consolidated Statements of Retained Earnings (Thousands of $)
The accompanying notes are an integral part of these consolidated financial statements.
LG&E Energy Corp. and Subsidiaries Consolidated Balance Sheets (Thousands of $)
The accompanying notes are an integral part of these consolidated financial statements.
LG&E Energy Corp. and Subsidiaries Consolidated Statements of Cash Flows (Thousands of $)
The accompanying notes are an integral part of these consolidated financial statements.
LG&E Energy Corp. and Subsidiaries Consolidated Statements of Capitalization (Thousands of $)
CUMULATIVE PREFERRED STOCK (Note 15):
LONG-TERM DEBT (Note 16):
Louisville Gas and Electric Company:
The accompanying notes are an integral part of these consolidated financial statements.
LG&E Energy Corp. and Subsidiaries Consolidated Statements of Capitalization (cont.) (Thousands of $)
The accompanying notes are an integral part of these consolidated financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1 - Summary of Significant Accounting Policies
Basis of Presentation. Effective May 4, 1998, following the receipt of all required state and federal regulatory approvals, LG&E Energy and KU Energy merged, with LG&E Energy as the surviving corporation. The accompanying consolidated financial statements reflect the accounting for the merger as a pooling of interests and are presented as if the companies were combined as of the earliest period presented. However, the financial information is not necessarily indicative of the results of operations, financial position or cash flows that would have occurred had the merger been consummated for the periods for which it is given effect, nor is it necessarily indicative of future results of operations, financial position, or cash flows. The financial statements reflect the conversion of each outstanding share of KU Energy common stock into 1.67 shares of LG&E Energy common stock. The outstanding preferred stock of LG&E, a subsidiary of LG&E Energy, and KU, a subsidiary of KU Energy, were not affected by the Merger.
Effective June 30, 1998, the Company discontinued its merchant energy trading and sales business and announced its plans to sell its natural gas gathering and processing business. In 1999 the Company chose to retain the natural gas gathering and processing business. Accordingly, the accompanying financial statements reflect the merchant energy trading and sales business as discontinued operations and the natural gas and processing business as continuing operations for all periods presented. See Note 3, Discontinued Operations and Note 4, Gas Facilities Business.
The consolidated financial statements include the accounts of LG&E Energy, LG&E, Capital Corp., KU, LEM and their respective wholly owned subsidiaries, collectively referred to herein as the Company.
LG&E Energy's operations include utility operations and non-utility operations. Capital Corp. has various subsidiaries referred to in these financial statements, including LPI, LII, WKE, and CRC.
All significant intercompany items and transactions have been eliminated from the consolidated financial statements. Certain reclassification entries have been made to the 1998 and 1997 financial statements to conform to the 1999 presentation with no impact on previously reported net income. The Company is exempt from regulation as a registered holding company under PUHCA.
Cash and Temporary Cash Investments. The Company considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. Temporary cash investments are carried at cost, which approximates fair value.
Gas Stored Underground. The costs of utility natural gas inventories are included in gas stored underground in the balance sheets as of December 31, 1999 and 1998. Utility gas inventories were $38.8 million and $33.5 million at December 31, 1999 and 1998, respectively. LG&E accounts for gas inventories using the average-cost method. Non-utility gas inventories as of December 31, 1999 and 1998 were $10.2 million and $5.8 million, respectively.
Utility Plant. LG&E's and KU's utility plant is stated at original cost, which includes payroll-related costs such as taxes, fringe benefits, and administrative and general costs. Construction work in progress has been included in the rate base for determining retail customer rates. Neither LG&E nor KU has recorded any significant allowance for funds used during construction.
The cost of utility plant retired or disposed of in the normal course of business is deducted from utility plant accounts and such cost, plus removal expense less salvage value, is charged to the reserve for depreciation.
When complete operating units are disposed of, appropriate adjustments are made to the reserve for depreciation, and gains and losses, if any, are recognized.
Depreciation and Amortization. Utility depreciation is provided on the straight-line method over the estimated service lives of depreciable plant. The amounts provided for LG&E were 3.4% in 1999, 1998 and 1997. The amounts provided for KU were 3.5% in 1999, 1998 and 1997.
Depreciation of non-utility plant and equipment is based on the straight-line method over periods ranging from 3 to 40 years for domestic operations. Intangible assets and goodwill have been allocated to the subsidiaries' lines of business and are being amortized over periods ranging up to 25 years.
Financial Instruments. The Company uses over-the-counter interest-rate swap agreements to hedge its exposure to interest rates. The Company also uses exchange-traded U.S. Treasury note and bond futures to hedge its exposure to fluctuations in the value of its investments in the preferred stocks of other companies. Gains and losses on interest-rate swaps used to hedge interest rate risk are reflected in interest charges monthly. Gains and losses on U.S. Treasury note and bond futures used to hedge investments in preferred stocks are initially deferred and classified as unrealized losses on marketable securities in common equity and then charged or credited to other income and deductions when the securities are sold. See Note 7, Financial Instruments.
In connection with the Company's marketing of power from owned or controlled generation assets, exchange traded futures are used to hedge its exposure to price risk. The Company also uses financial instruments associated with its discontinued merchant energy trading and sales business, the financial impact of which is included in discontinued operations. See Note 3, Discontinued Operations.
Debt Expense. Utility debt expense is amortized over the lives of the related bond issues, consistent with regulatory practices.
Deferred Income Taxes. Deferred income taxes have been provided for all material book-tax temporary differences.
Investment Tax Credits. Investment tax credits resulted from provisions of the tax law that permitted a reduction of the Company's tax liability based on credits for certain construction expenditures. Deferred investment tax credits are being amortized to income over the estimated lives of the related property that gave rise to the credits.
Common Stock. On May 4, 1998, 63,149,394 shares were issued to shareholders of KU Energy to effect the merger, and the KU Energy shares were retired. Prior period shares, dividends and earnings per share of common stock have been restated to reflect the exchange of KU Energy's shares for shares of LG&E Energy. Diluted earnings per share reflects the potential dilution that could occur if securities or other contracts to issue common stock under the Company's Omnibus Long-Term Incentive Plan and Stock Option Plan for Non-Employee Directors resulted in the issuance of common stock that then shared in the earnings of the Company. See Note 15 for more information about these plans.
Revenue Recognition. Utility revenues are recorded based on service rendered to customers through month-end. LG&E and KU accrue estimates for unbilled revenues from each meter reading date to the end of the accounting period. The unbilled revenue estimates included in accounts receivable for both LG&E and KU at December 31, 1999 and 1998, were approximately $60.7 million and $54.7 million, respectively. Under an agreement approved by the Kentucky Commission in 1994, LG&E implemented a demand-side management program, including a "decoupling mechanism" which allowed LG&E to recover a predetermined level of
revenue on electric and gas residential sales. In 1998, the decoupling mechanism was suspended. See Note 6, Utility Rates and Regulatory Matters.
Fuel and Gas Costs. The cost of fuel for electric generation is charged to expense as used, and the cost of gas supply is charged to expense as delivered to the distribution system. LG&E implemented a Kentucky Commission-approved experimental performance-based ratemaking mechanism related to gas procurement and off-system gas sales activity in October 1997. See Note 6, Utility Rates and Regulatory Matters.
Management's Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported assets and liabilities and disclosure of contingent items at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. See Note 18, Commitments and Contingencies, for a further discussion.
New Accounting Pronouncements. During 1999 and 1998, the following accounting pronouncements were issued that affect the Company:
SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or a liability measured at its fair value. SFAS No. 133 requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and requires that the Company must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. The Company has not yet quantified all the effects of adopting SFAS No. 133 on the financial statements. However, SFAS No. 133 could increase the volatility in earnings and other comprehensive income. The effect of this statement will be recorded in cumulative effect of change in accounting when adopted. SFAS No. 137, Accounting for Derivative Instruments and Hedging Activities -- Deferral of the Effective Date of SFAS No. 133, deferred the effective date of SFAS No. 133 until January 1, 2001.
EITF No. 98-10, Accounting for Energy Trading and Risk Management Activities was adopted effective January 1, 1999. The pronouncement requires that energy trading contracts to be marked to market on the balance sheet, with the gains and losses shown net in the income statement. EITF No. 98-10 more broadly defines what represents energy trading to include economic activities related to physical assets which were not previously marked to market by established industry practice. Adoption of EITF No. 98-10 did not have a material impact on the Company's consolidated results of operations or financial position.
SOP 98-5, Reporting on the Costs of Start-Up Activities and 98-1, Accounting for the Costs of Computer Software Developed or Obtained for Internal Use. SOP 98-5, adopted as of January 1, 1998, requires companies to expense the costs of start-up activities as incurred. The statement also requires certain previously capitalized costs to be charged to expense at the time of adoption as a cumulative effect of a change in accounting principle. The Company had previously capitalized start-up costs related to its investments in various unconsolidated ventures and other non-utility businesses. The cumulative effect of adoption resulted in a $7.2 million after-tax charge. The effect of this change on 1998 income before cumulative effect of changes in accounting principles was not significant. SOP 98-1, adopted as of January 1, 1998, clarifies the criteria for capital or expense treatment of costs incurred by an enterprise to develop or obtain computer software to be used in its internal operations. The statement does not change treatment of costs incurred in connection with correcting computer programs to properly process the millennium change to the Year 2000, which were expensed as incurred. Adoption of SOP 98-1 did not have a material effect on the Company's financial statements.
Note 2 - Mergers and Acquisitions
CRC-Evans. In July 1999, the Company purchased 100% of the outstanding common stock of CRC for initial consideration of $45.6 million and retirement of approximately $35.3 million in debt. CRC, based in Houston, Texas, is a provider of specialized equipment and services used in the construction and rehabilitation of gas and oil transmission pipelines. The purchase agreement provides for future annual earn-out payments to the previous owners based on CRC's meeting certain financial targets over the period ending March 31, 2002. The agreement caps the total of these payments at $34.3 million.
The purchase consideration was paid 55% in cash and 45% in LG&E Energy common stock. LG&E Energy will repurchase common stock from time to time in the open market or through privately negotiated transactions in amounts equal to the stock portions of the initial and subsequent earn-out payments. During the third quarter 1999, the Company purchased approximately 935,000 shares in this regard and completed the initial purchase installment.
The Company accounted for the acquisition using the purchase method and recorded goodwill of approximately $42.1 million. Additional goodwill will be recorded contingent upon future earn-out payments. Goodwill is being amortized over a period of twenty years.
The preliminary fair values of the net assets acquired follow (in thousands of $):
Assets $ 123,444 Liabilities 78,899 --------- Cash paid, excluding transaction costs 44,545 Cash and cash equivalents acquired 5,943 --------- Net cash paid, excluding transaction costs 38,602 Transaction costs 1,091 --------- Net cash paid $ 39,693 =========
The Company's pro forma results of operations for 1999 and 1998 follow (in thousands of $, except earnings per share). The results for each period assume the Company acquired CRC at the beginning of the period.
1999 1998 ---- ----
Revenues .................................... $ 2,746,477 $ 2,181,034 Net income (loss) ........................... 60,607 (77,934) Earnings (loss) per share (basic and diluted) .47 (.60)
These unaudited pro forma results have been prepared for comparative purposes only and include certain adjustments, such as additional amortization expense as a result of recorded goodwill and increased interest expense on borrowings used to finance the acquisition. The pro forma amounts presented do not purport to be indicative of the results of operations that would have actually occurred had the combination taken place as of January 1, 1998, nor are such amounts necessarily indicative of results that may occur in future periods.
Argentine Gas Distribution Companies. In March 1999, the Company acquired an indirect 20% ownership interest in Gas BAN, a natural gas distribution company that serves 1.1 million customers in the northern portion of the province of Buenos Aires, Argentina. The purchase price totaled $74.3 million, including transaction costs, which has been reflected in investments in unconsolidated ventures in the accompanying balance sheet. The Company accounted for the acquisition using the purchase method, and it records its share of earnings using the equity method. The purchase price exceeded the underlying equity in Gas BAN by $13.0 million. The Company allocated this difference to the assets and liabilities acquired based on their preliminary
estimated fair values. In the fourth quarter of 1999, the Company made an additional net investment in Gas BAN of approximately $11.1 million. These funds were used by the Company's Argentine holding company to repay its debt.
In February 1997, the Company acquired interests in two Argentine natural gas distribution companies for $140 million, plus transaction-related costs and expenses. The Company acquired a controlling interest in Centro and a combined 14.4% interest in Cuyana. The Company accounted for both acquisitions using the purchase method. The Company allocated substantially all of the excess of the purchase price over the underlying equity of Centro and Cuyana to property and equipment.
The fair values of the Centro and Cuyana net assets acquired follow (in thousands of $):
Assets $330,215 Liabilities 86,455 Minority interests 103,916 -------- Cash paid, excluding transaction costs 139,844 Cash and cash equivalents acquired 16,453 -------- Net cash paid, excluding transaction costs 123,391 Transaction costs 1,202 -------- Net cash paid $124,593 ========
Centro's revenues, cost of revenues and operating expenses since the date of acquisition are classified as components of international and non-utility in the income statement. The earnings of Cuyana are included in Equity in earnings of unconsolidated ventures. The Company includes Centro's property and equipment in Non-utility property and plant, net, in its balance sheet, and it includes its investment in Cuyana in Investments in unconsolidated ventures. Portions of Centro not owned directly or indirectly by the Company are reported as minority interests in the financial statements.
Liabilities assumed in the purchase included negotiable obligations issued by Centro with a face amount of $38 million. The obligations mature in August 2001, pay interest at 10.5% of face value and are classified as long-term debt.
KU Energy Corporation. LG&E Energy and KU Energy merged on May 4, 1998, with LG&E Energy as the surviving corporation. As a result of the merger, the Company, which is the parent of LG&E, became the parent company of KU. The operating utility subsidiaries (LG&E and KU) have continued to maintain their separate corporate identities and serve customers in Kentucky and Virginia under their present names. LG&E Energy has estimated approximately $760 million in gross non-fuel savings over a ten-year period following the merger. Costs to achieve these savings of $103.9 million were recorded in the second quarter of 1998, $38.6 million of which were initially deferred and are being amortized over a five-year period pursuant to regulatory orders. Primary components of the merger costs were separation benefits, relocation costs, and transaction fees, the majority of which were paid by December 31, 1998. The Company, LG&E and KU expensed the remaining costs associated with the merger ($65.3 million) in the second quarter of 1998. In regulatory filings associated with approval of the merger, LG&E and KU committed not to seek increases in existing base rates and proposed reductions in their retail customers' bills in amounts based on one-half of the savings, net of the deferred and amortized amount, over a five-year period. The preferred stock and debt securities of the operating utility subsidiaries were not affected by the merger. The non-utility subsidiaries of KU Energy have become subsidiaries of Capital Corp.
Pursuant to the merger, in accordance with the terms of the merger agreement, each outstanding share KU Energy Common Stock together with the associated KU Energy stock purchase rights, was converted into 1.67 shares LG&E Energy Common Stock, together with the associated LG&E Energy stock purchase rights.
Immediately preceding the merger, there were 66,527,636 shares of LG&E Energy common stock outstanding, and 37,817,517 shares of KU Energy common stock outstanding. Based on such capitalization, immediately following the merger, 51.3% of the outstanding LG&E Energy common stock was owned by the shareholders of LG&E Energy prior to the merger and 48.7% was owned by former KU Energy shareholders.
LG&E Energy, as the parent of LG&E and KU, continues to be an exempt holding company under PUHCA. Management has accounted for the merger as a pooling of interests and as a tax-free reorganization under the Internal Revenue Code.
In the application filed with the Kentucky Commission, the utilities proposed that 50% of the net non-fuel cost savings estimated to be achieved from the merger, less $38.6 million or 50% of the originally estimated costs to achieve such savings, be applied to reduce customer rates through a surcredit on customers' bills and the remaining 50% be retained by the companies. The Kentucky Commission approved the surcredit and allocated the customer savings 53% to KU and 47% to LG&E. The surcredit will be about 2% of customer bills over the next five years and will amount to approximately $55 million in net non-fuel savings to LG&E customers and approximately $63 million in net non-fuel savings to KU customers. Any fuel cost savings are passed to Kentucky customers through the companies' fuel adjustment clauses. See Note 6 for more information about LG&E's and KU's rates and regulatory matters.
Note 3 - Discontinued Operations
Effective June 30, 1998, the Company discontinued its merchant energy trading and sales business. This business consisted primarily of a portfolio of energy marketing contracts entered into in 1996 and early 1997, nationwide deal origination and some level of speculative trading activities, which were not directly supported by the Company's physical assets. The Company's decision to discontinue these operations was primarily based on the impact that volatility and rising prices in the power market had on its portfolio of energy marketing contracts. Exiting the merchant energy trading and sales business enabled the Company to focus on optimizing the value of physical assets it owns or controls, and reduced the earnings impact on continuing operations of extreme market volatility in its portfolio of energy marketing contracts. The Company continues to settle commitments that obligate it to buy and sell natural gas and electric power. If the Company is unable to dispose of these commitments or assets it will continue to meet its obligations under the terms of the contracts. The Company, however, has maintained sufficient market knowledge, risk management skills, technical systems and experienced personnel to maximize the value of power sales from physical assets it owns or controls, including LG&E, KU and WKE.
As a result of the Company's decision to discontinue its merchant energy trading and sales activity, and the initial decision to sell the associated gas gathering and processing business, the Company recorded an after-tax loss on disposal of discontinued operations of $225 million in the second quarter of 1998. The loss on disposal of discontinued operations resulted primarily from several fixed-price energy marketing contracts entered into in 1996 and early 1997, including the Company's long-term contract with OPC. Other components of the write-off included costs relating to certain peaking options, goodwill associated with the Company's 1995 purchase of merchant energy trading and sales operations and exit costs.
At the time the Company decided to discontinue its merchant energy trading and sales business, it also decided to sell its natural gas gathering and processing business. Effective June 30, 1999, the Company decided to retain this business. The accompanying financial statements reflect the reclassification of the natural gas gathering and processing business as continuing operations for all periods presented. Approximately $800,000 of net losses charged to the loss on disposal of discontinued operations was reclassified to continuing operations in the accompanying income statement in each of 1999 and 1998 related to the natural gas gathering and processing business. See Note 4 below.
In the fourth quarter of 1999, the Company received an adverse decision from the arbitration panel considering its contract dispute with OPC, which was commenced by the Company in April 1998. As a result of this adverse decision, higher than anticipated commodity prices, increased load demands, and other factors, the Company increased its after-tax accrued loss on disposal of discontinued operations by $175 million. The additional write-off included costs related to the remaining commitments in its portfolio and exit costs expected to be incurred to serve those commitments. Although the Company used what it believes to be appropriate estimates for future energy prices, among other factors, to calculate the net realizable value of discontinued operations, there are inherent limitations in models to accurately predict future commodity prices, load demands and other events that could impact the amounts recorded by the Company.
Actual operating results for each of the last three years ended December 31 for the discontinued merchant energy trading and sales business, follow (in thousands of $).
1999 1998 1997 ---- ---- ----
Revenues $ 747,983 $ 3,755,187 $ 3,147,484 Loss before taxes (175,940) (167,109) (41,989) Net loss (70,905) (109,431) (25,367)
Net (liabilities) assets of the merchant energy trading and sales business at December 31, follow (in thousands of $).
1999 1998 ---- ----
Cash and temporary cash investments $ -- $ 4,671 Accounts receivable 36,558 70,775 Price risk management assets, net 29,576 98,885 Non-utility property and plant, net -- 2,037 Accounts payable and accruals (25,233) (58,526) Price risk management liabilities, net (10,262) (32,693) Other assets and liabilities, net (18,163) 37,451 --------- ---------
Net assets before accrued loss on disposal of dis- continued operations 12,476 122,600
Accrued loss on disposal of discontinued operations, net of income tax benefit of $109,503 and $74,297 170,698 119,381 --------- ---------
Net assets (liabilities) of discontinued operations $(158,222) $ 3,219 ========= =========
Total pretax charges against the accrued loss on disposal of discontinued operations through December 31, 1999, include $251.0 million for commitments prior to disposal, $69.6 million for transaction settlements, $11.1 million for goodwill, and $30.5 million for other exit costs. While the Company has been successful in settling portions of its discontinued operations, significant assets, operations and obligations remain. The Company continues to manage the remaining portfolio and believes it has hedged certain of its future obligations through various power purchase commitments and planned construction of physical assets. Management cannot predict the ultimate effectiveness of these hedges.
The pretax net fair value of the remaining commitments as of December 31, 1999, are currently estimated to be approximately $46 million in 2000, $37 million to $54 million each year in 2001 through 2004 and $7 million in the aggregate thereafter.
As of December 31, 1999, the Company's discontinued operations were under various contracts to buy and sell power and gas with net notional amounts of 22.1 million Mwh's of power and 44.3 million Mmbtu's of natural gas with a volumetric weighted-average period of approximately 37 and 44 months, respectively. These notional amounts are based on estimated loads since various commitments do not include specified firm volumes. The Company is also under contract to buy or sell coal and SO2 allowances in support of its power contracts. Notional amounts reflect the nominal volume of transactions included in the Company's price risk management commitments, but do not reflect actual amounts of cash, financial instruments, or quantities of the underlying commodity which may ultimately be exchanged between the parties.
As of January 26, 2000, the Company estimates that a $1 change in electricity prices and a 10-cent change in natural gas prices across all geographic areas and time periods could change the value of the Company's remaining energy portfolio by approximately $4.9 million. In addition to price risk, the value of the Company's remaining energy portfolio is subject to operational and event risks including, among others, increases in load demand, regulatory changes, and forced outages at units providing supply for the Company. As of January 26, 2000, the Company estimates that a 1% change in the forecasted load demand could change the value of the Company's remaining energy portfolio by $8.2 million.
The Company's discontinued operations maintain policies intended to minimize credit risk and revalue credit exposures daily to monitor compliance with those policies. As of December 31, 1999, over 97% of the Company's price risk management commitments were with counterparties rated BBB equivalent or better. As of December 31, 1999, six counterparties represented 90% of the Company's price risk management commitments.
Note 4 - Gas Facilities Business
In June 1999, the Company reclassified its natural gas gathering and processing business to continuing operations from discontinued operations. The Company chose to retain rather than dispose of this business at the end of the one-year period established by accounting standards because of management's expectation of more favorable future natural gas and natural gas liquids prices and the related impact on this business. The Company has reflected the operating results and net assets of the natural gas gathering and processing business as continuing operations in the accompanying financial statements for all periods presented.
Operating results for the natural gas gathering and processing business follow (in thousands of $):
Three Six Months Months Ended Ended Mar. 31, Dec. 31, 1999 1998 ---- ----
Revenues $ 33,302 $ 48,942 Net loss (788) (852)
Net assets at December 31 follow (in thousands of $):
1999 1998 ---- ----
Cash and temporary cash investments $ 12,073 $ -- Accounts receivable 24,622 7,425 Non-utility property and plant, net 146,958 161,473 Accounts payable and accruals (6,274) (6,148) Goodwill and other assets and liabilities, net (29,018) (22,318) --------- ---------
Net assets $ 148,361 $ 140,432 ========= =========
No loss on disposal of the net assets of the natural gas gathering and processing business was included because the Company assumed it would sell these assets for an amount at least equal to book value. It also included an after-tax reserve of approximately $1.6 million for estimated losses from operations of the natural gas gathering and processing business through the date of disposal. Since this amount equaled the estimated losses from operations included in the original accrued loss on disposal of discontinued operations, no reversal of the accrued loss was included in income for 1999. The Company has recorded no impairment losses related to the net assets of its natural gas gathering and processing business.
Note 5 - Big Rivers Electric Corporation Lease
In July 1998, the Company closed the transaction to lease the generating assets of Big Rivers. Under the 25-year operating lease, WKE operates Big Rivers' coal-fired facilities, a combustion turbine and operates and maintains the Station Two generating facility of Henderson. The combined generating capacity of these facilities is approximately 1,700 Mw, net of Henderson's capacity and energy needs from Station Two. WKE prepaid $55.9 million for its first two years of lease payments. Lease expense for 1999 and 1998 was $27.9 million and $12.8 million, respectively. See Note 18, Commitments and Contingencies, for further discussion.
In related transactions, power is supplied to Big Rivers at contractual prices over the term of the lease to meet the needs of three-member distribution cooperatives and their retail customers, including major western Kentucky aluminum smelters. Excess generating capacity is available to WKE to market throughout the region. In connection with these transactions, WKE has undertaken to bear certain of the future capital requirements of those generating assets, certain defined environmental compliance costs and other obligations.
In July 1998, as part of the deal structure with Big Rivers, WKE began advancing Big Rivers $50 million over a 24-month period to help it emerge from bankruptcy. The note will be repaid over a three-year period, beginning August 2000, with interest at 7.165%.
Note 6 - Utility Rates and Regulatory Matters
Accounting for the regulated utility business conforms with generally accepted accounting principles as applied to regulated public utilities and as prescribed by FERC, the Kentucky Commission and the Virginia Commission. LG&E and KU are subject to SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. Under SFAS No. 71, certain costs that would otherwise be charged to expense are deferred as regulatory assets based on expected recovery from customers in future rates. Likewise, certain credits that would otherwise be reflected as income are deferred as regulatory liabilities based on expected flowback to customers in future rates. LG&E's and KU's current or expected recovery of deferred costs and expected flowback of deferred credits is generally based on specific ratemaking decisions or precedent for each item. The following regulatory assets and liabilities were included in the consolidated balance sheets as of December 31 (in thousands of $):
1999 1998 ---- ----
Unamortized loss on bonds $ 24,150 $ 26,302 Merger costs 27,026 34,749 Manufactured gas sites 2,185 3,684 Other 1,115 1,136 --------- --------- Total regulatory assets 54,476 65,871
Deferred income taxes - net (99,759) (109,411) Other (5,036) (670) --------- --------- Total regulatory liabilities (104,795) (110,081) --------- ---------
Regulatory liabilities - net $ (50,319) $ (44,210) ========= =========
Environmental Cost Recovery. In August 1994 and May 1995, respectively, KU and LG&E implemented an ECR surcharge. The Kentucky Commission's order approving the surcharge for KU as well as the constitutionality of the surcharge was challenged by certain intervenors in Franklin Circuit Court. Decisions of the Circuit Court and the Kentucky Court of Appeals in July 1995 and December 1997, respectively, upheld the constitutionality of the ECR statute but differed on a claim of retroactive recovery of certain amounts. Based on these decisions, the Kentucky Commission ordered that certain surcharge revenues collected by LG&E and KU be subject to refund pending final determination of all appeals.
In December 1998, the Kentucky Supreme Court rendered an opinion upholding the constitutionality of the surcharge statute but denied recovery of costs associated with pre-1993 environmental projects through the ECR. The court remanded the case to the Kentucky Commission to determine amounts to be refunded for revenues collected for such pre-1993 environmental projects. Accordingly, the Company recorded a provision for rate refunds of $26 million in December 1998.
The parties to the proceedings reached a settlement agreement that was approved in a Final Order issued by the Kentucky Commission in August 1999. This Final Order resulted in the reversal of approximately $0.9 million of the provision for rate refunds established by KU and LG&E in December 1998. The refund is being applied to customers' bills during the twelve-month period beginning October 1999.
Future Rate Regulation. In October 1998, LG&E and KU filed applications with the Kentucky Commission for approval of a new method of determining electric rates that sought to provide financial incentives for LG&E and KU to further reduce customers' rates. The filing was made pursuant to the September 1997 Kentucky Commission order approving the merger of LG&E Energy and KU Energy, wherein the Kentucky Commission directed LG&E and KU to indicate whether they desired to remain under traditional rate of return regulation or commence non-traditional regulation. The proposed ratemaking method, known as PBR, included financial
incentives for LG&E and KU to reduce fuel costs and increase generating efficiency, and to share any resulting savings with customers. Additionally, the PBR proposal provided for financial penalties and rewards to assure continued high quality service and reliability.
In April 1999, LG&E and KU filed a joint agreement among the companies and the Kentucky Attorney General to adopt the PBR plan subject to certain amendments. The amended filing included requested Kentucky Commission approval of a five-year rate reduction plan which proposed to reduce the electric rates of LG&E and KU by $20 million in the first year (beginning July 1999), and by $8 million annually through June 2004. The proposed amended plan also included establishment of a $6 million program for low-income customer assistance as well as extension for one additional year of both the rate cap proposal and merger savings surcredit established in the original merger plan of LG&E and KU. Under the rate cap proposal, the companies agreed, in the absence of extraordinary circumstances, not to increase base electric rates for five years following the merger and LG&E also agreed to refrain from filing for an increase in natural gas rates through June 2004.
In April 1999, the Kentucky Commission issued initial orders implementing the amended PBR plan, effective July 1999, and subject to modification. The Kentucky Commission also consolidated into the continuing PBR proceedings an earlier March 1999, rate complaint by a group of industrial intervenors, KIUC, in which KIUC requested significant reductions in electric rates. Hearings were conducted before the Kentucky Commission on LG&E's and KU's amended PBR plans and the KIUC rate reduction petitions in August and September 1999. Legal briefs of the parties were filed with the Kentucky Commission in October 1999. KIUC's position called for annual revenue reductions for LG&E and KU of $69.6 million and $61.5 million, respectively.
In January 2000, the Kentucky Commission issued Orders for LG&E and KU in the subject cases. The Kentucky Commission ruled that LG&E and KU should reduce base rates by $27.2 million and $36.5 million, respectively, effective with bills rendered beginning March 1, 2000. The Kentucky Commission eliminated the utilities' proposal to operate under its PBR plan and reinstated the FAC mechanism effective March 1, 2000. The Kentucky Commission offered the utilities the opportunity to operate under an ESM for the next three years. Under this mechanism, incremental annual earnings for each utility resulting in a rate of return either above or below a range of 10.5% to 12.5% would be shared 60% with shareholders and 40% with ratepayers.
Later in January 2000, the utilities filed motions for correction to the January 2000 orders for computational and other errors made in the Kentucky Commission's orders which produced overstatements in the base rate reductions to LG&E and KU of $1.1 million and $7.7 million, respectively. The utilities also filed motions for reconsideration with the Kentucky Commission on a number of items in the case in late January. Certain intervening parties in the proceedings have also filed motions for reconsideration asserting, among other things, that the Kentucky Commission understated the amount of base rate reductions.
Other Rate Matters. LG&E's rates contain a DSM provision. The provision includes a rate mechanism that provides concurrent recovery of DSM costs and provides an incentive for implementing DSM programs. This program had allowed LG&E to recover revenues from lost sales associated with the DSM program (decoupling), but in 1998, LG&E and customer interest groups requested an end to the decoupling rate mechanism. In September 1998, the Kentucky Commission accepted LG&E's modified tariff discontinuing the decoupling mechanism effective as of June 1, 1998.
Since October 1997, LG&E has implemented an experimental performance-based ratemaking mechanism related to gas procurement activities and off-system gas sales only. During the three-year test period beginning October 1997, rate adjustments related to this mechanism are being determined for each 12-month period beginning November 1 and ending October 31. During the first two years of the mechanism ended October 31, 1999 and 1998, LG&E recorded $2.2 million and $3.5 million, respectively, for its share of reduced gas costs. These amounts are billed to customers through the gas supply clause.
Prior to implementation of the PBR in July 1999, and following its termination in March 2000, LG&E and KU employed an FAC mechanism, which under Kentucky law allowed the utilities to recover from customers the actual fuel costs associated with retail electric sales. In February 1999, LG&E received orders from the Kentucky Commission requiring a refund to retail electric customers of approximately $3.9 million resulting from reviews of the FAC from November 1994 through April 1998, of which $1.9 million was refunded in April 1999 for the period beginning November 1994 and ending October 1996. The orders changed the utilities' method of computing fuel costs associated with electric line losses on off-system sales appropriate for recovery through the FAC. LG&E requested that the Kentucky Commission grant rehearing on the February orders, and further requested that the Kentucky Commission stay the refund requirement until it could rule on the rehearing request. The Kentucky Commission granted the request for a stay, and in March 1999 granted rehearing on the appropriate line loss factor associated with off-system sales for the 18-month period ended April 1998. The Kentucky Commission also granted rehearing on the KIUC's request for rehearing on the Kentucky Commission's determination that it lacked authority to require the utilities to pay interest on the refund amounts. The Kentucky Commission conducted a hearing on the rehearing issues and issued a final ruling in December 1999. The Kentucky Commission agreed with LG&E 's position on the appropriate loss factor to use in the FAC computation and reduced the refund level for the 18-month period under review to approximately $800,000. LG&E implemented the refund with billings beginning in the month of January 2000. LG&E and KIUC have each filed separate appeals from the Kentucky Commission's February 1999 orders with the Franklin Circuit Court. A decision on the appeals by the Court is expected in 2000.
In July 1999, the Kentucky Commission issued a series of orders requiring KU to refund approximately $10.1 million resulting from reviews of the FAC from November 1994 to October 1998. The orders changed KU's method of computing fuel costs associated with electric line losses on off-system sales appropriate for recovery through the FAC, and KU's method for computing system line losses for the purpose of calculating the system sales component of the FAC charge. At KU's request, in July 1999, the Kentucky Commission stayed the refund requirement pending the Kentucky Commission's final determination of any rehearing request that KU may file. In August 1999, KU filed its request for rehearing of the July orders.
In August 1999, the Kentucky Commission issued a Final Order in the KU proceedings, agreeing, in part, with KU's arguments outlined in its Petition for Rehearing. While the Kentucky Commission confirmed that KU should change its method of computing the fuel costs associated with electric line losses, it agreed with KU that the line loss percentage should be based on KU's actual line losses incurred in making off-system sales rather than the percentage used in its Open Access Transmission Tariff. The Kentucky Commission also upheld its previous ruling concerning the computation of system line losses in the calculation of the FAC. The net effect of the Kentucky Commission's Final Order was to reduce the refund obligation to $5.8 million from the original Order amount of $10.1 million. In August 1999, LG&E and KU each recorded its estimated share of anticipated FAC refunds of $8.7 million. KU began implementing the refund in October and will continue the refund through September 2000. Both KU and the KIUC have appealed the Order to the Franklin Circuit Court. A decision is not expected on the appeal until later in 2000.
LG&E intends to file before the end of the first quarter an application with the Kentucky Commission for authority to increase its natural gas rates in order to recoup higher costs for providing natural gas distribution services. LG&E expects implementation before the end of 2000.
Kentucky PSC Administrative Case for Affiliate Transactions. In December 1997, the Kentucky Commission opened Administrative Case No. 369 to consider Kentucky Commission policy regarding cost allocations, affiliate transactions and codes of conduct governing the relationship between utilities and their non-utility operations and affiliates. The Kentucky Commission intends to address two major areas in the proceedings: the tools and conditions needed to prevent cost shifting and cross-subsidization between regulated and non-utility operations; and whether a code of conduct should be established to assure that non-utility
segments of the holding company are not engaged in practices that could result in unfair competition caused by cost shifting from the non-utility affiliate to the utility. In September 1998, the Kentucky Commission issued a draft code of conduct and cost allocation guidelines. In January 1999, the Company, as well as all parties to the proceeding, filed comments on the Kentucky Commission draft proposals. In December 1999, the Kentucky Commission issued guidelines on cost allocation and held a hearing in January 2000, on the draft code of conduct. Management does not expect the ultimate resolution of this matter to have a material adverse effect on the Company's financial position or results of operations.
Note 7 - Financial Instruments
The cost and estimated fair values of the Company's non-trading financial instruments (excluding the fair values of the Company's price risk management assets and liabilities) as of December 31, 1999 and 1998 follow (in thousands of $):
All of the above valuations reflect prices quoted by exchanges except for the swaps and the long-term investments. The fair values of the swaps reflect price quotes from dealers or amounts calculated using accepted pricing models. The fair values of the long-term investments reflect cost, since the Company cannot reasonably estimate fair value.
Interest Rate Swaps. The Company enters into interest rate swap agreements to exchange fixed and variable interest rate payment obligations without the exchange of underlying principal amounts. As of December 31, 1999 and 1998, the Company was party to various interest rate swaps with aggregate notional amounts of $487.3 million and $349.3 million, respectively. Under swap agreements the Company paid fixed rates averaging 4.53% and 4.55% and received variable rates of averaging 5.61% and 4.42% at December 31, 1999 and 1998, respectively. The Company also paid variable rates averaging 6.46% and received fixed rates averaging 7.13% at December 31, 1999. The swaps mature on dates ranging from 2000 to 2025.
At December 31, 1999, the Company held U.S. Treasury note and bond futures contracts with notional amounts totaling $6.1 million. These contracts are used to hedge price risk associated with certain marketable securities and mature in March 2000.
Note 8 - Concentrations of Credit and Other Risk
Credit risk represents the accounting loss that would be recognized at the reporting date if counterparties failed to perform as contracted. Concentrations of credit risk (whether on- or off-balance sheet) relate to groups of
customers or counterparties that have similar economic or industry characteristics that would cause their ability to meet contractual obligations to be similarly affected by changes in economic or other conditions.
LG&E's customer receivables and gas and electric revenues arise from deliveries of natural gas to approximately 295,000 customers and electricity to approximately 366,000 customers in Louisville and adjacent areas in Kentucky. KU's customer receivables and revenues arise from deliveries of electricity to about 458,000 customers in over 600 communities and adjacent suburban and rural areas in 77 counties in central, southeastern and western Kentucky and to about 29,000 customers in five counties in southwestern Virginia. For the year ended December 31, 1999, 91% of total utility revenue was derived from electric operations and 9% from gas operations.
The financial position and results of operations of the domestic unconsolidated ventures are substantially dependent upon the continuation of long-term power sales contracts with purchasing utilities. The Argentine natural gas distribution companies serve approximately 1.9 million customers in seven provinces in Argentina. WKE's receivables and revenues arise from the deliveries of electricity and generating capacity to Big Rivers for distribution to its three member distribution cooperatives and other major wholesale customers. CRC has a concentration of customers in the oil and gas pipeline construction industry, which experiences cyclical fluctuations, and its receivables are collateralized on a limited basis with negotiable letters of credit. Ten of CRC's customers were responsible for 50% of its revenues for the period July 1, 1999, through December 31, 1999.
In August 1999, KU and their employees represented by IBEW Local 101 and USWA Local 8686, which represents approximately 14% of KU's workforce, entered into a one-year collective bargaining agreement. In December 1998, LG&E and IBEW Local 2100 employees, which represent approximately 60% of LG&E's workforce, entered into a three-year collective bargaining agreement. In September 1998, WKE and IBEW Local 1701 employees entered into a three-year collective bargaining agreement. CRC contracts with employees represented by applicable locals of the LIU and the UAJ-APPI on a project basis.
Note 9 - Investments in Unconsolidated Ventures
The Company's investments in unconsolidated ventures reflect interests in domestic and foreign electric power and steam producing plants and two of the Argentine gas distribution companies. These investments are accounted for using the equity method.
The fuel type, ownership percentages and carrying amounts of the unconsolidated ventures as of December 31, 1999, are summarized as follows (in thousands of $):
The Company's carrying amount exceeded the underlying equity in unconsolidated ventures by $39.8 million and $33.3 million at December 31, 1999 and 1998, respectively. This difference, which is being amortized, represents adjustments to reflect the fair value of the underlying net assets acquired and related goodwill.
In March 1999, LG&E-Westmoreland Rensselaer, a California general partnership in which the Company owns a 50% interest, sold substantially all the assets and major contracts of its 79 Mw gas-fired cogeneration facility in Rensselaer, New York, with net proceeds to the Company of approximately $34 million. The sale resulted in an after-tax gain to the Company of approximately $8.9 million.
In January 1999, a final order was entered in the bankruptcy proceedings involving Westmoreland Coal Company and certain of its subsidiaries, including Westmoreland Energy, Inc., the parent of various entities that are partners with company subsidiaries in five of the independent generating facilities. However, none of the partnerships and no partner of the current partnerships has been under bankruptcy court protection, nor were these partnerships in a default occasioned under the project loan documents.
With respect to the Wind projects listed above, certain of the Company's partners (or affiliates of such partners) are in bankruptcy proceedings. During the third quarter of 1998, the Company wrote off its aggregate remaining investment in Windpower Partners 1994 of $3.8 million. During 1999, the Wind projects received certain amounts in connection with such bankruptcy proceedings. See Note 18, Commitments and Contingencies.
In November 1998, the Company received approximately $8.5 million in connection with an arbitration proceeding concerning a former PPA between Tenaska Washington Partners II, L.P. and the BPA. The Company has a 10% interest in this partnership, which owned a partially constructed facility in Frederickson, Washington. This facility was transferred to the BPA following payment of the award.
In June 1998, the partnership that owns the Rensselaer facility, along with 14 other independent power producers, participated in the consummation of a MRA with NIMO. As part of the MRA, the partnership restructured its power purchase agreement with NIMO and entered into a new multi-year agreement with the utility. Concurrent with the MRA, the Company reached a settlement with other parties to retain a 50%
ownership in the Rensselaer facility. As a result of these transactions, the Company recorded a $21 million, net after-tax gain in 1998.
In June 1998, the Company sold half of its interest in the Gregory, Texas, project and became a 50% partner in the 550 Mw gas-fired project. The project is currently under construction and anticipated to become operational in mid-2000. See Note 18, Commitments and Contingencies.
In February 1998, the Company sold its indirect, one-third interest in the company which owned and operated the San Miguel, Argentina generating facility for a price of $16 million. The sale resulted in a $2.8 million pre-tax charge to 1998 earnings.
Note 10 - Leveraged Leases
During 1999, all of the Company's leveraged leases in which Capital Corp. owned an equity interest expired. The lessees who leased five of the turbines exercised their options to purchase resulting in pre-tax gains totaling $3.1 million. The lessee who leased the remaining three turbines allowed its leases to terminate and Capital Corp. is investigating options on the future use of these turbines. The carrying value of Capital Corp.'s investment the three remaining turbines totals $9.1 million, and the Company has reclassified this amount to Investment in Unconsolidated Ventures at December 31, 1999. See Note 9, Investment in Unconsolidated Ventures and Note 18, Commitments and Contingencies.
The following is a summary of the components of Capital Corp.'s net investment in leveraged leases at December 31, 1998 (in thousands of $):
Rents receivable (net of nonrecourse debt) $ 1,556 Estimated residual value of leased property 32,707 Less: unearned and deferred income 3,319 ------- Investment in leveraged leases 30,944 Less: accumulated deferred income taxes 7,301 ------- Net investment in leveraged leases $23,643 =======
See Note 14, Other Income and Deductions for income from leveraged leases.
Note 11 - Marketable Securities
The Company's marketable securities have been determined to be "available-for-sale" under the provisions of SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities. Proceeds from sales of available-for-sale securities in 1999 were approximately $11.7 million, which resulted in realized gains of approximately $.7 million and losses of approximately $.2 million, calculated using the specific identification method. Proceeds from sales of available-for-sale securities in 1998 were $20 million, which resulted in realized gains of approximately $.2 million and losses of approximately $.7 million.
Approximate cost, fair value and other required information pertaining to the Company's available-for-sale securities by major security type, as of December 31, 1999 and 1998, follow (in thousands of $):
Fixed Equity Income Total -------- -------- -------- 1999: Cost $ 7,529 $ 3,033 $ 10,562 Unrealized gains 170 3 173 Unrealized losses (498) (111) (609) -------- -------- -------- Fair values $ 7,201 $ 2,925 $ 10,126 ======== ======== ========
Fair values: No maturity $ 7,201 $ -- $ 7,201 Contractual maturities: Less than one year -- 2,134 2,134 One to five years -- 631 631 Five to ten years -- 160 160 -------- -------- -------- Total fair values $ 7,201 $ 2,925 $ 10,126 ======== ======== ========
1998: Cost $ 6,467 $ 14,134 $ 20,601 Unrealized gains 545 40 585 Unrealized losses (196) (128) (324) -------- -------- -------- Fair values $ 6,816 $ 14,046 $ 20,862 ======== ======== ========
Fair values: No maturity $ 6,816 $ 178 $ 6,994 Contractual maturities: Less than one year -- 8,301 8,301 One to five years -- 3,861 3,861 Over ten years -- 1,706 1,706 -------- -------- -------- Total fair values $ 6,816 $ 14,046 $ 20,862 ======== ======== ========
Note 12 - Pension Plans and Retirement Benefits
Pension Plans and Retirement Benefits. LG&E Energy Corp. sponsors several qualified and non-qualified pension plans and other postretirement benefit plans for its employees. The following tables provide a reconciliation of the changes in the plans' benefit obligations and fair value of assets over the three-year period ending December 31, 1999, and a statement of the funded status as of December 31 for each of the last three years (in thousands of $):
There are no plan assets in the nonqualified plan due to the nature of the plan.
The following tables provide the amounts recognized in the balance sheet and information for plans with benefit obligations in excess of plan assets as of December 31, 1999, 1998 and 1997 (in thousands of $):
(1) All years include LG&E's non-union plan, LG&E Energy's plan and the Company's unfunded SERPs. 1999 and 1998 also include WKE's union plan. (2) All years include the Company's SERPs plus in 1999 WKE's union plan and in 1998 LG&E's non-union plan, LG&E Energy's plan and WKE's union plan.
The following table provides the components of net periodic benefit cost for the plans for 1999, 1998 and 1997 (in thousands of $):
On May 4, 1998, LG&E Energy and KU Energy merged, with LG&E Energy as the surviving corporation. At the time of the merger KU Energy had both qualified and nonqualified pension plans. During 1998, the Company invested approximately $24.0 million in special termination benefits as a result of its early retirement program offered to eligible employees post-merger. In May 1997, $4.7 million in lump sum payments were
made to retired employees of KU Energy due to a change-in-control provision in the Supplemental Security Plan of the Merger Agreement.
The assumptions used in the measurement of the Company's pension benefit obligation are shown in the following table:
(1) All plans used 8.50% for 1998 and 1997 except KU's. (2) All plans used 4.00% for 1998 and 1997 except LG&E's union plan which used 3.50% for 1998 and 2.00% for 1997.
For measurement purposes, a 7.00% annual increase in the per capita cost of covered health care benefits was assumed for 2000. The rate was assumed to decrease gradually to 4.75% for 2005 and remain at that level thereafter.
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A 1% change in assumed health care cost trend rates would have the following effects (in thousands of $):
Thrift Savings Plans. The Company has thrift savings plans under section 401(k) of the Internal Revenue Code. Under these plans, eligible employees may defer and contribute to the plans a portion of current compensation in order to provide future retirement benefits. The Company makes contributions to the plans by matching a portion of the employee's contributions. The costs of this matching were approximately $6.4 million, $6.0 million and $4.7 million for 1999, 1998 and 1997, respectively.
Note 13 - Income Taxes
Components of income tax expense are shown in the table below (in thousands of $):
Net deferred tax liabilities resulting from book-tax temporary differences are shown below (in thousands of $):
1999 1998 ---- ----
Deferred tax liabilities: Depreciation and other plant-related items $716,064 $683,023 Other liabilities 44,117 39,550 -------- -------- 760,181 722,573 -------- --------
Deferred tax assets: Investment tax credit 34,642 37,878 Income taxes due to customers 39,300 43,021 Deferred income 11,294 11,626 Accrued liabilities not currently deductible and other 89,065 61,945 -------- -------- 174,301 154,470 -------- --------
Net deferred income tax liability $585,880 $568,103 ======== ========
At December 31, 1999, there were $89.9 million of net operating loss carryforwards related to discontinued operations. These carryforwards, which expire in 2000 through 2009, are subject to an annual limitation of approximately $6 million under provisions of the Internal Revenue Code, and realization is dependent upon generating sufficient taxable income prior to their expiration. At December 31, 1999 and 1998, the Company recorded valuation allowances related to these deferred tax assets of $22.8 million and $25.6 million, respectively. Unamortized goodwill will be reduced if unrecorded net operating loss carryforwards are realized.
A reconciliation of differences between the statutory U.S. federal income tax rate and the Company's effective income tax rate as a percentage of income from continuing operations before income taxes and preferred dividends follows:
Note 14 - Other Income and Deductions
Other income and deductions consisted of the following at December 31 (in thousands of $):
1999 1998 1997 ---- ---- ----
Income from leveraged leases $ 3,205 $ 4,273 $ 3,974 Interest and dividend income 9,803 10,552 10,159 Gains (losses) on disposals - net 3,801 (4,942) 7,083 Other 2,496 (1,783) 467 -------- -------- --------
Total other income and (deductions) $ 19,305 $ 8,100 $ 21,683 ======== ======== ========
Note 15 - Capital Stock
Changes in shares of common stock outstanding are shown in the table below (in thousands). The amounts in the table have been restated to reflect the merger-related exchange of 1.67 shares of LG&E Energy common stock for each share of KU Energy common stock.
1999 1998 1997 ---- ---- ----
Outstanding January 1 129,677 129,683 129,497 Issues under the Employee Common Stock Purchase Plan ($1,613) -- -- 77 Issues under the Omnibus Long-Term Incentive Plan ($2,195) -- -- 109 Merger-related buy-back of fractional shares -- (6) -- -------- -------- --------
Outstanding December 31 129,677 129,677 129,683 ======== ======== ========
The Company's shareholders approved an increase in the Company's authorized shares of common stock from 125.0 million to 300.0 million in October 1997 in conjunction with the proposed merger with KU Energy. This increase was effective at the consummation of the merger on May 4, 1998.
The Company has an Omnibus Long-Term Incentive Plan, under which nonqualified stock options, performance units and stock appreciation rights have been granted to key personnel. Pursuant to an amendment approved by the Company's shareholders in April 1999, a total of approximately 6.5 million shares, including prior issuances, of common stock may be issued under the plan. Performance units are paid out on a three-year rolling basis in 50% stock and 50% cash based on Company performance. Directors of the Company receive stock options pursuant to the Stock Option Plan for Non-Employee Directors. A total of 500,000 shares of common stock may be issued under this plan. Each option entitles the holder to acquire one share of the Company's stock no earlier than one year from the date granted. The options are granted at market value and generally expire 10 years from the date granted. In October 1997, the Company announced a repurchase program authorizing the repurchase of up to 1.0 million shares of its common stock to be used for, among other things, benefit and compensation plans, including the Long-Term Plan, and has funded the plans via open market purchases since that date. The Company also repurchased approximately 935,000 shares during 1999 in connection with the funding of its acquisition of CRC.
A summary of the status of the Company's nonqualified stock options follows:
Common stock equivalents resulting from the options granted under both the Long-Term Plan and the Directors' Plan would not have a material dilutive effect on reported earnings per share.
The Company has a Shareholders' Rights Plan designed to protect shareholders' interests in the event the Company is ever confronted with an unfair or inadequate acquisition proposal. Pursuant to the plan, each share of common stock has one-third of a "right" entitling the holder to purchase from the Company one one-hundredth of a share of new preferred stock of the Company under certain circumstances. The holders of the rights will, under certain conditions, also be entitled to purchase either shares of common stock of LG&E Energy or common stock of the acquirer at a reduced percentage of market value. The rights will expire on December 19, 2000.
In December 1997, Inversora, a subsidiary of the Company that holds part of the Company's interest in Centro, issued 302,364 shares of preferred stock to unaffiliated parties. The stock has a nominal value of $10 per share and a variable dividend consisting of 5% of Inversora's annual net income. Inversora can redeem the shares at the nominal value upon shareholder approval. During 1998, Inversora redeemed 200,275 shares of preferred stock. During 1999, Inversora redeemed the remaining 102,089 shares.
Note 16 - Long-Term Debt
Long-term debt and the current portion of long-term debt, summarized below (in thousands of $), consists primarily of first mortgage bonds and pollution control bonds issued by LG&E and KU, and medium-term notes issued by Capital Corp. Interest rates and maturities in the table below are for the amounts outstanding at December 31, 1999.
Under the provisions for LG&E's and KU's variable-rate pollution control bonds, the bonds are subject to tender for purchase at the option of the holder and to mandatory tender for purchase upon the occurrence of certain events, causing the bonds to be classified as current portion of long-term debt. The average annualized interest rate for these bonds were 3.98% and 3.35% for LG&E's and KU's bonds, respectively.
Maturities of long-term debt outstanding (principal amounts stated in thousands of $) at December 31, 1999, are summarized below.
2001 $ 37,873 2002 20,091 2003 104,623 2004 150,000 2005 -- Thereafter 986,828 ---------- Total $1,299,415 ==========
In December 1999, LG&E notified bondholders of its intent to exercise its call option on its $20.0 million 7.50% First Mortgage Bonds due July 1, 2002. The bonds were redeemed in January 2000 utilizing proceeds from the issuance of commercial paper.
In May 1999, Capital Corp. issued $150 million of medium-term notes due May 2004 with an effective rate of 6.13%.
In September 1999, Capital Corp. issued $50.0 million of floating-rate notes under its medium-note program that mature in September 2000. The notes bear interest at a rate of one-month LIBOR plus 10 basis points.
In November 1998, Capital Corp. issued $150 million of Reset Put Securities due 2011 with an effective rate of 5.4% through October 2001. As of November 1, 2001, the securities will be subject to automatic purchase by a
remarketing agent and either the interest rate will be reset or the bonds will be repurchased by Capital Corp.
In June 1998, $20 million of LG&E's First Mortgage Bonds matured and were retired.
In February 1998, Capital Corp. issued $150 million of medium-term notes due in January 2008, with an effective rate of 6.82%.
Annual requirements for the sinking funds of LG&E's First Mortgage Bonds (other than the First Mortgage Bonds issued in connection with certain Pollution Control Bonds) are the amounts necessary to redeem 1% of the highest principal amount of each series of bonds at any time outstanding. Property additions (166 2/3% of principal amounts of bonds otherwise required to be so redeemed) have been applied in lieu of cash.
Substantially all of LG&E's and KU's utility plants are pledged as security for its First Mortgage Bonds. LG&E's indenture, as supplemented, provides in substance that, under certain specified conditions, portions of retained earnings will not be available for the payment of dividends on common stock. No portion of retained earnings is presently restricted by this provision.
Note 17 - Notes Payable
Capital Corp. had outstanding commercial paper of $329.5 million at December 31, 1999, at a weighted-average interest rate of 5.97%. Capital Corp. had notes payable of $365.1 million at December 31, 1998, at a weighted-average interest rate of 5.19%.
LG&E's short-term financing requirements are satisfied through the sale of commercial paper. LG&E had outstanding commercial paper of $120.1 million at December 31, 1999, at a weighted-average interest rate of 6.02%. LG&E had no short-term borrowings at December 31, 1998.
KU's short-term financing requirements are satisfied through the sale of commercial paper. KU had no short-term borrowings at December 31, 1999, and 1998.
At December 31, 1999, the Companies had lines of credit in place totaling $900 million ($200 million for LG&E and $700 million for Capital Corp.) for which they pay commitment or facility fees. The LG&E credit facility provides support of commercial paper borrowings. The Capital Corp. facility provides for short-term borrowing, letter of credit issuance, and support of commercial-paper borrowings. Unused capacity under these lines totaled $395.6 million after considering the commercial paper support and approximately $51.7 million in letters of credit securing on- and off-balance sheet commitments. The Capital Corp. and LG&E credit lines will expire at various times from 2000 through 2002. Management expects to renegotiate these lines when they expire. The KU credit facilities that provided for short-term borrowing and support of commercial paper borrowing expired on December 31, 1999.
The lenders under the credit facilities, commercial paper program, and medium-term notes for Capital Corp. are entitled to the benefits of a Support Agreement with LG&E Energy. The Support Agreement states, in substance, that LG&E Energy will provide Capital Corp. with the necessary funds and financial support to meet their obligations under the credit facilities, commercial paper program, and medium-term notes.
Note 18 - Commitments and Contingencies
Construction Program
The Company had commitments, primarily in connection with the construction program of LG&E and KU,
aggregating approximately $28 million at December 31, 1999. LG&E's construction expenditures for 2000 and 2001 are estimated to total approximately $401 million. KU's construction expenditures for the same period are estimated to total approximately $324 million. Non-utility construction expenditures for the same two-year period are estimated to be $123 million.
Letters of Credit
Capital Corp. has provided letters of credit issued to third parties to secure certain off-balance sheet obligations (including contingent obligations) of its subsidiaries. The letters of credit securing such obligations totaled approximately $27.9 million and $30.7 million at December 31, 1999 and 1998, respectively. These letters of credit are subject to Support Agreements as more fully described in Note 17, Notes Payable.
Capital Corp. has provided a guarantee of a lease obligation to a third party. The obligation totaled $4.9 million and $7.6 million at December 31, 1999 and 1998, respectively.
Projects
Springfield Municipal Contract. In January 2000, LEM reached a settlement with CWLP regarding a suit previously pending before the United States District Court for the Western District of Kentucky. Pursuant to the settlement, CWLP paid LEM approximately $16.6 million, $4.0 million less than expected. The dispute involved CWLP's 1998 failure to sell electric energy to LEM pursuant to an existing contract between the parties.
Monroe Project. In 1999, a subsidiary of the Company entered into an operating lease wherein it agreed to lease three combustion turbines and related facilities to be installed and constructed at a 450 Mw natural gas-fired merchant power generation plant being developed by the Company in Monroe, Georgia. The lease has a five year term, but no rent is payable until the turbines have been completed and installed, currently anticipated in June 2001. At the end of the lease term, the Company may purchase the leased assets or assist the lessor in selling them. If the assets are sold, the Company is obligated to make up any deficiency between the lease balance and the proceeds subject to a cap. The total value of assets under the lease is expected to be approximately $175 million.
Texas Project. In October 1999, a subsidiary of the Company entered into an initial agreement to purchase six natural gas combustion turbines and is negotiating terms of a definitive agreement. In connection therewith, the Company is pursuing initial development of a possible 1,600 Mw generation facility in Anderson County, Texas. Should the plant be developed as presently planned, the aggregate cost is estimated to be approximately $790 million, portions of which may be independently financed or shared with eventual outside partners.
Roanoke Valley I. The Company owns a 50% interest in WLP, the owner of the Roanoke Valley I facility which sells electric power to VEPCO pursuant to a PPA. From May 1994 through December 1999, VEPCO withheld approximately $19.8 million of capacity payments during periods of forced outages. In October 1994, WLP filed a complaint against VEPCO seeking damages related to the withholding of such payments. In June 1997, the Virginia Supreme Court reversed a lower court ruling granting summary judgment in favor of VEPCO and remanded the case for a trial which occurred in October 1998. In November 1998, the Circuit Court for the City of Richmond, Virginia issued a decision awarding WLP approximately $19 million, plus interest until paid, and ruled WLP was entitled to receive future capacity payments for eligible forced outages during the remainder of the PPA term. In January 1999, VEPCO filed a notice of appeal to the Supreme Court of Virginia regarding the Circuit Court decision. Appellate briefs were filed by the parties during1999 and a hearing was held in January 2000. A decision is anticipated in the first half of 2000. Pending resolution of all appeals by VEPCO, the Company has not recognized any income on its 50% portion of the capacity payments
being withheld by VEPCO. In the Company's opinion, WLP is entitled to recover the withheld capacity payments, as well as the future capacity payments during forced outages. The Company does not expect the ultimate resolution of this matter to have a material adverse effect on its results of operations or financial condition.
Southampton. In October 1998, LG&E-Westmoreland Southampton and VEPCO entered into a settlement agreement which resolved issues pending before the FERC regarding the status of the Southampton as a QF under PURPA for the year 1992, including the possible payment of FERC-ordered refunds by Southampton of capacity payments previously received from VEPCO for such year. The settlement, which has been approved by the FERC, provides for, among other items, payments by Southampton to VEPCO of $1 million annually for the years 1999-2001, followed by a reduction in capacity payments from VEPCO to Southampton by $500,000 annually for the years 2002-2008. Following 2008, VEPCO may elect to terminate its power purchases from Southampton or continue to receive the annual reduction in capacity payments for the remainder of the power purchase agreement. The Company has also been notified that its partners in the Southampton partnership are disputing their responsibilities for their share of the refunds and are asserting that the Company should bear full responsibility for such amounts. In December 1999, the Company settled with one of its partners regarding its claims and is currently negotiating these matters with the remaining partner. The Company does not believe that the disputes with its partners, including the settlement already achieved with the one partner, will have a material adverse effect on its results of operations or financial condition.
Gregory Project. In June 1998, LPI entered into a partnership with Columbia Electric Corporation for the development of a natural gas-fired cogeneration project in Gregory, Texas, providing electricity and steam equivalent of 550 Mw. Initial construction commenced in August 1998 and non-recourse financing for a majority of the construction and other costs was obtained in November 1998. The project will sell steam and a portion of its electric output to Reynolds Metals Company. A medium-term fixed-price contract has also been entered into with a third party for a portion of the remaining electric output. The project is expected to begin commercial operation in the summer of 2000 at an anticipated total project cost of approximately $240 million. The Company's equity contribution is expected to be approximately $30 to $35 million in connection with its 50% interest in the project.
Windpower Partners 1994. WPP 94 is a windpower generation facility in Texas, in which the Company has a 25% interest. Since September 1997 WPP 94 has not made its semiannual payments, due in March and September each year, to Hancock under certain Notes issued by WPP 94 to Hancock. WPP 94 and Hancock have entered into cash sweep and standstill agreements, with the standstill term currently extended through March 2001, regarding the Notes and are presently engaged in discussions concerning a possible restructuring of WPP 94's debt obligations. Because of the continuing nature of the negotiations, the Company is not able to predict the outcome of this event. The Company wrote off its aggregate investment in WPP94 in 1998 and does not expect the ultimate resolution of this matter to have a material effect on its results of operations or financial condition.
Kenetech Bankruptcy. In May 1996, Kenetech filed in the United States Bankruptcy Court in the Northern District of California for protection under Chapter 11 of the United States Bankruptcy Code seeking, among other things, to restructure certain contractual commitments between Kenetech and its subsidiaries, and various windpower projects located in the U.S. and abroad. Included in these projects are the WPP 93, WPP 94 and Tarifa wind projects in which the Company has invested, collectively, approximately $31 million. As part of the bankruptcy proceeding, Kenetech is also seeking to void certain warranty commitments made to the owners of those projects with respect to the operation and output of the facilities, and the repair and replacement of the windpower generation equipment located there. In January 1997, the projects filed their respective breach of contract and other claims against Kenetech in the bankruptcy proceeding. In April 1999, the Bankruptcy Court approved a final plan of reorganization. Three initial distributions pursuant to the Plan were made during 1999
of which the Company's share was approximately $7.45 million, which funds were primarily used directly by the projects to pay unpaid interest and principal on debt of the projects and legal fees. The WPP93 and WPP94 projects are discussing a restructuring of their debt with their creditors, including certain revisions to ownership structure and operating arrangements. Final bankruptcy plan distributions and completion of the project restructurings are currently anticipated during the second quarter of 2000. While the Company is unable to predict the outcome of these events, it does not expect the ultimate resolution of the bankruptcy or the restructurings to have a material adverse effect on its results of operations or financial condition.
Calgary. In November 1996, LG&E Natural Canada Inc., a subsidiary of LEM, initiated action in the Court of the Queens Bench of Alberta, Calgary against a former employee. An amended statement of claim was filed in the Calgary action in December 1996, naming additional parties. These lawsuits were filed as a result of LEM's discovery in the fourth quarter of 1996 that the former employee had engaged in unauthorized transactions. Counterclaims have been filed seeking damages of approximately $40 million for, among other things, defamation and breach of contract. In the second quarter of 1997, the Company received an insurance settlement of $7.6 million (net of expenses) related to the losses. Discovery proceedings in this action have continued during 1999. The Company does not expect the ultimate resolution of this matter to have a material adverse effect on its results of operations or financial condition.
Operating Leases
The Company leases office space, office equipment and vehicles and accounts for these leases as operating leases. See also Note 5 for discussion of the Big Rivers Electric Corporation operating lease. Total lease expense for 1999, 1998 and 1997, was $37.1 million, $21.7 million and $6.7 million, respectively. The future minimum annual lease payments under lease agreements for years subsequent to December 31, 1999, are as follows (in thousands of $):
2000 $ 19,574 2001 42,735 2002 47,605 2003 46,896 2004 216,448 Thereafter 593,028 -------- Total $966,286 ========
Future minimum annual lease payments have been reduced by rental payments to be received from noncancelable subleases of approximately $1.9 million in 2000, and $1.3 million in 2001.
In December 1999, LG&E and KU entered into an 18-year cross-border lease of its two combustion turbines recently installed at KU's Brown facility. The utilities' obligations were defeased upon consummation of the cross-border lease. The transaction produced a pre-tax gain of approximately $3.1 million which has been deferred pending resolution of rate treatment by the Kentucky Commission.
LG&E Power Monroe LLC, a subsidiary of Capital Corp., entered into a five-year operating lease expiring on December 31, 2004, to finance the purchase and construction of a 450-Mw gas-fired peaking facility in Monroe, Georgia. No lease payments are due during construction and payments will be based on commercial paper rates upon completion of the plant. Currently, the plant is expected to be completed by mid-2001. The cost of the leased assets is expected to total approximately $175 million.
Environmental
The Act imposed stringent new SO2 and NOx emission limits on electric generating units. LG&E previously had installed scrubbers on all of its generating units, while KU met its Phase I SO2 requirements primarily through installation of a scrubber on Ghent Unit 1. The Company's combined strategy for Phase II, commencing January 1, 2000, is to use accumulated emissions allowances to delay additional capital expenditures and may also include fuel switching or the installation of additional scrubbers. LG&E, KU, and WKE met the NOx emission requirements of the Act through installation of low-NOx burner systems. The Company's compliance plans are subject to many factors including developments in the emission allowance and fuel markets, future regulatory and legislative initiatives, and advances in clean air control technology. The Company will continue to monitor these developments to ensure that its environmental obligations are met in the most efficient and cost-effective manner.
In September 1998, the EPA announced its final "NOx SIP call" rule requiring significant additional reductions in NOx emissions by May 2003, in order to mitigate alleged ozone transport to the Northeast. While each of the 22 states covered by the rule is free to allocate its assigned NOx reductions among various emissions sectors as it deems appropriate, the regulation may ultimately require electric generating units to reduce their NOx emissions to 0.15 lb./Mmbtu - an 85% reduction from 1990 levels. In related proceedings in response to petitions filed by various Northeast states, in December 1999, EPA issued a final rule directing similar NOx reductions from a number of specifically named electric generating units including all LG&E and KU stations in the eastern half of Kentucky. Additional petitions currently pending before EPA may potentially result in orders encompassing the remaining KU and WKE stations. Several states, various labor and industry groups, and individual companies have appealed both EPA rulings to the U.S. Court of Appeals for the Washington D.C. Circuit. Management is currently unable to determine the outcome or exact impact of this matter until such time as the courts rule on the pending legal challenges and the states implement the final regulatory mandate. However, if the 0.15 lb. target is ultimately imposed, LG&E, KU, and WKE and the independent power projects in which the Company has an interest will be required to incur significant capital expenditures and increased operation and maintenance costs for additional controls.
Subject to further study, analysis, and the outcome of pending litigation against the EPA, the Company estimates that it may incur approximate capital costs for NOx compliance ranging from $300 million to reduce emissions to the level of 0.25 lb./Mmbtu (Commonwealth of Kentucky's proposed NOx compliance level) to $550 million to reduce emissions to the level of 0.15 lb./Mmbtu (current EPA regulations). These costs would generally be incurred beginning in 2000. The Company believes its costs in this regard to be comparable to those of similarly situated utilities with like generation assets. LG&E and KU anticipate that such capital and operating costs are the type of costs that are eligible for recovery from customers under their environmental surcharge mechanisms and believe that a significant portion of such costs could be recovered. However, Kentucky Commission approval is necessary and there can be no guarantee of recovery.
The Company is also addressing other air quality issues. First, the Company is monitoring the status of EPA's revised NAAQS for ozone and particulate matter. In May 1999, the Washington D.C. Circuit remanded the final rule and directed EPA to undertake additional rulemaking efforts. The Company continues to monitor EPA actions to challenge that ruling. Second, the Company was notified by regulatory agencies that the Cane Run Station may be the source of a potential exceedance of the NAAQS that could require the Company to incur additional capital expenditures or accept certain emissions limitations. After reviewing additional modeling information submitted by the Company, in January 2000, EPA concluded that the Cane Run Station does not contribute to any potential NAAQS exceedance and that no further action is required from the Company. Third, the Company is working with regulatory authorities to review the effectiveness of remedial measures aimed at controlling particulate emissions from its Mill Creek Station. The Company previously settled a number of property damage claims from adjacent residents and completed significant plant modifica-
tions as part of its ongoing capital construction program.
The Company owns or formerly owned several properties which contained past MGP operations. Various contaminants are typically found at such former MGP sites and environmental remediation measures are frequently required. The Company has completed the cleanup of a site owned by KU and reached agreements for other parties to assume cleanup responsibility for two other sites formerly owned by LG&E. In addition, the Company recently reached an agreement with the Kentucky Division of Waste Management with respect to a third LG&E-owned site in which the Company committed to impose certain property restrictions and conduct additional monitoring in lieu of a cleanup. Based on currently available information, management estimates that it will incur additional MGP costs of less than $500,000. Accordingly, an accrual of $500,000 has been recorded in the accompanying financial statements. With respect to other former MGP sites no longer owned by the Company, the Company is unable to determine what, if any, additional exposure or liability it may have as it lacks complete information on current site conditions.
In October 1999, approximately 38,000 gallons of diesel fuel leaked from a cracked valve in an underground pipeline at KU's E.W. Brown Station. Under the oversight of EPA and state officials, the Company commenced immediate spill containment and recovery measures which prevented the spill from reaching the Kentucky River. The Company ultimately recovered approximately 34,000 gallons of diesel fuel. In November 1999, the Kentucky Division of Water issued a notice of violation for the incident. The Company is currently negotiating with the state in an effort to reach a complete resolution of this matter. To date the Company has incurred costs of approximately $1 million. The Company does not expect to incur any material additional amounts.
Purchased Power
KU has purchase power arrangements with OMU, EEI and other parties. Under the OMU agreement, which expires on January 1, 2020, KU purchases all of the output of a 400-Mw generating station not required by OMU. The amount of purchased power available to KU during 2000-2004, which is expected to be approximately 7% of KU's total kWh requirements, is dependent upon a number of factors including the units' availability, maintenance schedules, fuel costs and OMU requirements. Payments are based on the total costs of the station allocated per terms of the OMU agreement, which generally follows delivered kWh. Included in the total costs is KU's proportionate share of debt service requirements on $172 million of OMU bonds outstanding at December 31, 1999. The debt service is allocated to KU based on its annual allocated share of capacity, which averaged approximately 46% in 1999.
KU has a 20% equity ownership in EEI, which is accounted for on the equity method of accounting. KU's entitlement is 20% of the available capacity of a 1,000 Mw station. Payments are based on the total costs of the station allocated per terms of an agreement among the owners, which generally follows delivered kWh. See Note 9.
KU has several other contracts for purchased power during 2000 - 2004 of various Mw capacities and for varying periods with a maximum entitlement at any time of 62 Mw.
The estimated future minimum annual payments under purchased power agreements for the five years ended December 31, 2004, are as follows (in thousands of $):
2000 $ 28,765 2001 31,495 2002 30,683 2003 30,947 2004 31,155 -------- Total $153,045 ========
Note 19 - Jointly Owned Electric Utility Plant
LG&E owns a 75% undivided interest in Trimble County Unit 1. Accounting for the 75% portion of the Unit, which the Kentucky Commission has allowed to be reflected in customer rates, is similar to LG&E's accounting for other wholly owned utility plants.
Of the remaining 25% of the Unit, IMEA owns a 12.12% undivided interest, and IMPA owns a 12.88% undivided interest. Each is responsible for its proportionate ownership share of fuel cost, operation and maintenance expenses, and incremental assets.
The following data represents shares of the jointly owned property:
Note 20 - Segments of Business and Related Information
Effective December 31, 1998, the Company adopted SFAS No. 131, Disclosure About Segments of an Enterprise and Related Information. The Company's principal business segments consist of LG&E's regulated electric and gas utility operations, KU's regulated electric utility operations and its non-utility operations, including its Power Operations, WKE, Argentine gas distribution and other.
The All Other category consists of elimination entries, adjustments and other corporate. The Company does not allocate all expenses from corporate to reportable segments. International long-lived assets consist of the long-lived assets of the Argentine gas distribution companies, the Company's investment in the San Miguel project in Argentina (sold in February 1999), and its investment in the Tarifa project in Spain. The Company acquired its interest in Gas BAN in March 1999, and it acquired its interests in Centro and Cuyana in February 1997. Financial data for business segments, revenues by product, and long-lived assets by geographic area follow (in thousands of $):
Revenue By Product:
Asset-Based Retail Retail Energy Year Electric Gas Marketing Other Totals - ---- -------- --- --------- ----- ------
1999 $1,220,048 $333,828 $826,446 $326,954 $2,707,276
1998 1,189,185 339,707 390,567 166,787 2,086,246
1997 1,173,275 358,193 158,294 142,984 1,832,746
Long-Lived Assets By Geographic Area:
Inter- Year Domestic national Totals - ---- -------- -------- ------
1999 $4,011,839 $416,199 $4,428,038
1998 3,876,640 299,444 4,176,084
1997 3,647,358 360,106 4,007,464
Note 21 - Selected Quarterly Data (Unaudited)
Selected financial data for the four quarters of 1999 and 1998 are shown below. Because of seasonal fluctuations in temperature and other factors, results for quarters may fluctuate throughout the year.
(Thousands of $ except per share data) Quarters Ended March June September December ----- ---- --------- -------- Revenues $ 599,265 $ 623,657 $ 865,390 $ 618,964
Operating income 117,364 111,689 172,163 93,379
Net income (loss): Continuing operations 56,779 49,965 87,166 42,353 Gain (loss) on disposal of discontinued operations 788 -- -- (175,000) --------- --------- --------- --------- Total 57,567 49,965 87,166 (132,647)
Earnings per share of common stock (basic and diluted): Continuing operations .44 .39 .67 .33 Gain on disposal of discon- tinued operations -- -- -- (1.35) --------- --------- --------- --------- Total .44 .39 .67 (1.02)
Revenues $ 480,564 $ 472,188 $ 629,176 $ 504,318
Operating income 94,669 73,534 157,361 55,679
Net income (loss): Continuing operations 46,218 13,003 78,854 20,597 Discontinued operations (3,050) (19,802) -- -- Gain (loss) on disposal of dis- continued operations -- (225,000) 658 194 Cumulative effect of account- ing change (7,162) -- -- -- --------- --------- --------- --------- Total 36,006 (231,799) 79,512 20,791
Earnings per share of common stock (basic and diluted): Continuing operations .36 .10 .61 .16 Discontinued operations (.02) (.16) -- -- Loss on disposal of discon- tinued operations -- (1.73) -- -- Cumulative effect of account- ing change (.06) -- -- -- --------- --------- --------- --------- Total .28 (1.79) .61 .16
Note 22 - Subsequent Events
On February 28, 2000, the Company announced that its Board of Directors accepted an offer to be acquired by PowerGen for cash of approximately $3.2 billion or $24.85 per share and the assumption of $2.2 billion of the Company's debt. Pursuant to the acquisition agreement, among other things, LG&E Energy will become a wholly owned subsidiary of PowerGen and its U.S. headquarters. The Utility Operations of the Company will continue their separate identities and serve customers in Kentucky and Virginia under their present names. The preferred stock and debt securities of the Utility Operations will not be affected by this transaction resulting in the Utility Operations' obligation to continue to file SEC reports. The acquisition is expected to close 9 to 12 months from the announcement, shortly after all of the conditions to consummation of the acquisition are met. Those conditions include, without limitation, the approval of the holders of a majority of the outstanding shares of common stock of each of LG&E Energy and PowerGen, the receipt of all necessary governmental approvals and the making of all necessary governmental filings, including approvals of various regulators in Kentucky and Virginia under state utility laws, the approval of the FERC under the FPA, the approval of the SEC under the PUHCA of 1935, and the filing of requisite notifications with the Federal Trade Commission and the Department of Justice under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, and the expiration of all applicable waiting periods thereunder. Shareholder meetings to vote upon the approval of the acquisition are expected to be held during the second quarter of 2000 for both LG&E Energy and PowerGen. During the first quarter of 2000, the Company expensed approximately $1.0 million relating to the PowerGen transaction. The foregoing description of the acquisition does not purport to be complete and is qualified in its entirety by reference to LG&E Energy's current reports on Form 8-K, filed February 29, 2000, with the SEC.
On March 3, 2000, the U.S. Court of Appeals for the Washington D.C. Circuit issued a final opinion upholding the NOx SIP call rule requiring electric generating units to reduce their NOx emissions to 0.15 lb./Mmbtu by May 2003. Some of the litigants will likely seek further judicial review of the ruling.
In March 2000, the Virginia Supreme Court, remanded the Company's case against VEPCO, pertaining to capacity payments withheld from its Roanoke Valley I joint venture, for a new trial. Since the Company has not recognized any revenue in its financial statements the remand to the trial court will have no adverse effect on the Company's financial results.
In the first quarter of 2000, the Company will take a restructuring charge of approximately $15 million pre-tax relating to the reduction of approximately 250 positions and the integration of LG&E's and KU's operations, including combining retail gas and electric operations, consolidation of customer service centers and the redesigning various other processes.
The Kentucky Commission responded to the motions filed by the utilities for computational and other errors made in Orders received on base rate reductions in February 2000 by reducing KU's annual revenue reductions by $2.5 million and granting rehearings for LG&E and KU on other issues.
LG&E Energy Corp. REPORT OF MANAGEMENT
The management of LG&E Energy Corp. and subsidiaries is responsible for the preparation and integrity of the consolidated financial statements and related information included in this Annual Report. These statements have been prepared in accordance with generally accepted accounting principles applied on a consistent basis and, necessarily, include amounts that reflect the best estimates and judgment of management.
The Company's financial statements have been audited by Arthur Andersen LLP, independent public accountants. Management has made available to Arthur Andersen LLP all the Company's financial records and related data as well as the minutes of shareholders' and directors' meetings. Management has established and maintains a system of internal controls that provides reasonable assurance that transactions are completed in accordance with management's authorization, that assets are safeguarded and that financial statements are prepared in conformity with generally accepted accounting principles. Management believes that an adequate system of internal controls is maintained through the selection and training of personnel, appropriate division of responsibility, establishment and communication of policies and procedures and by regular reviews of internal accounting controls by the Company's internal auditors. Management reviews and modifies its system of internal controls in light of changes in conditions and operations, as well as in response to recommendations from the internal auditors. These recommendations for the year ended December 31, 1999, did not identify any material weaknesses in the design and operation of the Company's internal control structure.
The Audit Committee of the Board of Directors is composed entirely of outside directors. In carrying out its oversight role for the financial reporting and internal controls of the Company, the Audit Committee meets regularly with the Company's independent public accountants, internal auditors and management. The Audit Committee reviews the results of the independent accountants' audit of the consolidated financial statements and their audit procedures, and discusses the adequacy of internal accounting controls. The Audit Committee also approves the annual internal auditing program and reviews the activities and results of the internal auditing function. Both the independent public accountants and the internal auditors have access to the Audit Committee at any time.
LG&E Energy Corp. and subsidiaries maintain and internally communicate a written code of business conduct that addresses, among other items, potential conflicts of interest, compliance with laws, including those relating to financial disclosure and the confidentiality of proprietary information.
LG&E Energy Corp. and Subsidiaries REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders of LG&E Energy Corp.:
We have audited the accompanying consolidated balance sheets and statements of capitalization of LG&E Energy Corp. (a Kentucky corporation) and subsidiaries as of December 31, 1999 and 1998, and the related consolidated statements of income, retained earnings, cash flows and comprehensive income for each of the three years in the period ended December 31, 1999. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of LG&E Energy Corp. and subsidiaries as of December 31, 1999 and 1998, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1999, in conformity with accounting principles generally accepted in the United States.
Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule listed under Item 14(a)2 is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audit of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
Louisville, Kentucky Arthur Andersen LLP January 26, 2000 (Except with respect to the matters discussed in Note 22, as to which the date is March 3, 2000.)
Louisville Gas and Electric Company Statements of Income (Thousands of $)
Statements of Retained Earnings (Thousands of $)
The accompanying notes are an integral part of these financial statements.
Louisville Gas and Electric Company Statements of Comprehensive Income (Thousands of $)
The accompanying notes are an integral part of these financial statements.
Louisville Gas and Electric Company Balance Sheets (Thousands of $)
The accompanying notes are an integral part of these financial statements.
Louisville Gas and Electric Company Statements of Cash Flows (Thousands of $)
The accompanying notes are an integral part of these financial statements.
Louisville Gas and Electric Company Statements of Capitalization (Thousands of $)
CUMULATIVE PREFERRED STOCK: Redeemable on 30 days notice by LG&E
The accompanying notes are an integral part of these financial statements.
Louisville Gas and Electric Company Notes to Financial Statements
Note 1 - Summary of Significant Accounting Policies
LG&E is a subsidiary of LG&E Energy. LG&E is a regulated public utility that is engaged in the generation, transmission, distribution, and sale of electric energy and the storage, distribution, and sale of natural gas in Louisville and adjacent areas in Kentucky. LG&E Energy is an exempt energy services holding company with wholly-owned subsidiaries consisting of LG&E, KU, Capital Corp., and LEM. All of the LG&E's Common Stock is held by LG&E Energy.
Utility Plant. LG&E's plant is stated at original cost, which includes payroll-related costs such as taxes, fringe benefits, and administrative and general costs. Construction work in progress has been included in the rate base for determining retail customer rates. LG&E has not recorded any allowance for funds used during construction.
The cost of plant retired or disposed of in the normal course of business is deducted from plant accounts and such cost, plus removal expense less salvage value, is charged to the reserve for depreciation. When complete operating units are disposed of, appropriate adjustments are made to the reserve for depreciation and gains and losses, if any, are recognized.
Depreciation. Depreciation is provided on the straight-line method over the estimated service lives of depreciable plant. The amounts provided for 1999 were 3.4% (3.2% electric, 3.2% gas, and 7.1% common); for 1998 were 3.4% (3.2% electric, 3.4% gas, and 7.4% common); and for 1997 were 3.4% (3.2% electric, 3.3% gas, and 6% common) of average depreciable plant.
Cash and Temporary Cash Investments. LG&E considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. Temporary cash investments are carried at cost, which approximates fair value.
Gas Stored Underground. Gas inventories of $38.8 million and $33.5 million at December 31, 1999 and 1998, respectively, are included in gas stored underground in the balance sheet. The inventory is accounted for using the average-cost method.
Financial Instruments. LG&E uses over-the-counter interest-rate swap agreements to hedge its exposure to fluctuations in the interest rates it pays on variable-rate debt. LG&E also uses exchange-traded U.S. Treasury note and bond futures to hedge its exposure to fluctuations in the value of its investments in the preferred stocks of other companies. Gains and losses on interest-rate swaps used to hedge interest rate risk are reflected in interest charges monthly. Gains and losses on U.S. Treasury note and bond futures used to hedge investments in preferred stocks are initially deferred and classified as unrealized losses on marketable securities in common equity and then charged or credited to other income and deductions when the securities are sold. See Note 4, Financial Instruments.
In connection with LG&E's marketing of power from owned generation assets, exchange traded futures are used to hedge its exposure to price risk. Gains and losses on these futures contracts are reflected in other income and deductions, but are immaterial to LG&E's results of operations. At December 31, 1999, the value of these futures contracts was not material to LG&E's financial position.
Debt Expense. Debt expense is amortized over the lives of the related bond issues, consistent with regulatory practices.
Deferred Income Taxes. Deferred income taxes have been provided for all material book-tax temporary differences.
Investment Tax Credits. Investment tax credits resulted from provisions of the tax law that permitted a reduction of LG&E's tax liability based on credits for certain construction expenditures. Deferred investment tax credits are being amortized to income over the estimated lives of the related property that gave rise to the credits.
Revenue Recognition. Revenues are recorded based on service rendered to customers through month-end. LG&E accrues an estimate for unbilled revenues from each meter reading date to the end of the accounting period. The unbilled revenue estimates included in accounts receivable for LG&E at December 31, 1999 and 1998, were approximately $31.1 million and $25.1 million, respectively. Under an agreement approved by the Kentucky Commission in 1994, LG&E implemented a demand side management program, including a "decoupling mechanism" which allowed LG&E to recover a predetermined level of revenue on electric and gas residential sales. In 1998, the decoupling mechanism was suspended. See Note 3, Rates and Regulatory Matters.
Fuel and Gas Costs. The cost of fuel for electric generation is charged to expense as used, and the cost of gas supply is charged to expense as delivered to the distribution system. LG&E implemented a Kentucky Commission-approved experimental performance-based ratemaking mechanism related to gas procurement and off-system gas sales activity in October 1997. See Note 3, Rates and Regulatory Matters.
Management's Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported assets and liabilities and disclosure of contingent items at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. See Note 12, Commitments and Contingencies, for a further discussion.
New Accounting Pronouncements. During 1999 and 1998, the following accounting pronouncements were issued that affect LG&E:
SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or a liability measured at its fair value. SFAS No. 133 requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and requires that LG&E must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. LG&E has not yet quantified all the effects of adopting SFAS No. 133 on the financial statements. However, SFAS No. 133 could increase the volatility in earnings and other comprehensive income. The effect of this statement will be recorded in cumulative effect of change in accounting when adopted. SFAS No. 137, Accounting for Derivative Instruments and Hedging Activities -- Deferral of the Effective Date of SFAS No. 133, deferred the effective date of SFAS No. 133 until January 1, 2001.
EITF No. 98-10, Accounting for Energy Trading and Risk Management Activities was adopted effective January 1, 1999. The pronouncement requires that energy trading contracts to be marked to market on the balance sheet, with the gains and losses shown net in the income statement. EITF No. 98-10 more broadly defines what represents energy trading to include economic activities related to physical assets which were not previously marked to market by established industry practice. Adoption of EITF No. 98-10 did not have a material impact on LG&E's consolidated results of operations or financial position.
SOP 98-1, Accounting for the Costs of Computer Software Developed or Obtained for Internal Use. Adopted
as of January 1, 1998, SOP 98-1 clarifies the criteria for capital or expense treatment of costs incurred by an enterprise to develop or obtain computer software to be used in its internal operations. The statement does not change treatment of costs incurred in connection with correcting computer programs to properly process the millennium change to the Year 2000, which were expensed as incurred. Adoption of SOP 98-1 did not have a material effect on LG&E's financial statements.
Note 2 - Merger
LG&E Energy and KU Energy merged on May 4, 1998, with LG&E Energy as the surviving corporation. As a result of the merger, the LG&E Energy, which is the parent of LG&E, became the parent company of KU. The operating utility subsidiaries (LG&E and KU) have continued to maintain their separate corporate identities and serve customers in Kentucky and Virginia under their present names. LG&E Energy has estimated approximately $760 million in gross non-fuel savings over a ten-year period following the merger. Costs to achieve these savings for LG&E of $50.2 million were recorded in the second quarter of 1998, $18.1 million of which were initially deferred and are being amortized over a five-year period pursuant to regulatory orders. Primary components of the merger costs were separation benefits, relocation costs, and transaction fees, the majority of which were paid by December 31, 1998. LG&E expensed the remaining costs associated with the merger ($32.1 million) in the second quarter of 1998. In regulatory filings associated with approval of the merger, LG&E committed not to seek increases in existing base rates and proposed reductions in their retail customers' bills in amounts based on one-half of the savings, net of the deferred and amortized amount, over a five-year period. The preferred stock and debt securities of LG&E were not affected by the merger.
LG&E Energy, as the parent of LG&E and KU, continues to be an exempt holding company under PUHCA. Management has accounted for the merger as a pooling of interests and as a tax-free reorganization under the Internal Revenue Code.
In the application filed with the Kentucky Commission, the utilities proposed that 50% of the net non-fuel cost savings estimated to be achieved from the merger, less $18.1 million or 50% of the originally estimated costs to achieve such savings, be applied to reduce customer rates through a surcredit on customers' bills and the remaining 50% be retained by the companies. The Kentucky Commission approved the surcredit and allocated the customer savings 53% to KU and 47% to LG&E. The surcredit will be about 2% of customer bills over the next five years and will amount to approximately $55 million in net non-fuel savings to LG&E. Any fuel cost savings are passed to Kentucky customers through the companies' fuel adjustment clauses. See Note 3 for more information about LG&E's rates and regulatory matters.
Note 3 - Rates and Regulatory Matters
Accounting for the regulated utility business conforms with generally accepted accounting principles as applied to regulated public utilities and as prescribed by FERC and the Kentucky Commission. LG&E is subject to SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. Under SFAS No. 71, certain costs that would otherwise be charged to expense are deferred as regulatory assets based on expected recovery from customers in future rates. Likewise, certain credits that would otherwise be reflected as income are deferred as regulatory liabilities based on expected flowback to customers in future rates. LG&E's current or expected recovery of deferred costs and expected flowback of deferred credits is generally based on specific ratemaking decisions or precedent for each item. The following regulatory assets and liabilities were included in LG&E's balance sheets as of December 31 (in thousands of $):
1999 1998 ---- ----
Unamortized loss on bonds $ 16,556 $ 17,627 Merger costs 12,702 16,332 Manufactured gas sites 2,185 3,684 -------- -------- Total regulatory assets 31,443 37,643 -------- --------
Deferred income taxes - net (56,767) (63,529) Deferred net gain (1,959) -- -------- -------- Total regulatory liabilities (58,726) (63,529) -------- --------
Regulatory liabilities - net $(27,283) $(25,886) ======== ========
Environmental Cost Recovery. In May 1995, LG&E implemented an ECR surcharge. The Kentucky Commission's order approving the surcharge for KU as well as the constitutionality of the surcharge was challenged by certain intervenors in Franklin Circuit Court. Decisions of the Circuit Court and the Kentucky Court of Appeals in July 1995 and December 1997, respectively, upheld the constitutionality of the ECR statute but differed on a claim of retroactive recovery of certain amounts. Based on these decisions, the Kentucky Commission ordered that certain surcharge revenues collected by LG&E be subject to refund pending final determination of all appeals.
In December 1998, the Kentucky Supreme Court rendered an opinion upholding the constitutionality of the surcharge statute but denied recovery of costs associated with pre-1993 environmental projects through the ECR. The court remanded the case to the Kentucky Commission to determine amounts to be refunded for revenues collected for such pre-1993 environmental projects. Accordingly, LG&E recorded a provision for rate refunds of $4.5 million in December 1998.
The parties to the proceedings reached a settlement agreement that was approved in a Final Order issued by the Kentucky Commission in August 1999. This Final Order resulted in the additional accrual of approximately $.6 million to what had been recorded in December 1998. The refund is being applied to customers' bills during the twelve-month period beginning October 1999.
Future Rate Regulation. In October 1998, LG&E filed an application with the Kentucky Commission for approval of a new method of determining electric rates that sought to provide continued financial incentives for LG&E to further reduce customers' rates. The filing was made pursuant to the September 1997 Kentucky Commission order approving the merger of LG&E Energy and KU Energy, wherein the Kentucky Commission directed LG&E to indicate whether they desired to remain under traditional rate of return regulation or commence non-traditional regulation. The proposed ratemaking method, known as PBR, included financial incentives for LG&E to reduce fuel costs and increase generating efficiency, and to share any resulting savings
with customers. Additionally, the PBR proposal provided for financial penalties and rewards to assure continued high quality service and reliability.
In April 1999, LG&E filed a joint agreement with KU and the Kentucky Attorney General to adopt the PBR plan subject to certain amendments. The amended filing included requested Kentucky Commission approval of a five-year rate reduction plan which proposed to reduce the electric rates of LG&E by $9.4 million in the first year (beginning July 1999), and by $3.8 million annually through June 2004. The proposed amended plan also included establishment by LG&E of a $2.8 million program for low-income customer assistance as well as extension for one additional year of both the rate cap proposal and merger savings surcredit established in the original merger plan of LG&E and KU. Under the rate cap proposal LG&E agreed, in the absence of extraordinary circumstances, not to increase base electric rates for five years following the merger and LG&E also agreed to refrain from filing for an increase in natural gas rates through June 2004.
In April 1999, the Kentucky Commission issued initial orders implementing the amended PBR plan, effective July 1999, and subject to modification. The Kentucky Commission also consolidated into the continuing PBR proceedings an earlier March 1999, rate complaint by a group of industrial intervenors, KIUC, in which KIUC requested significant reductions in electric rates. Hearings were conducted before the Kentucky Commission on LG&E's amended PBR plan and the KIUC rate reduction petitions in August and September 1999. Legal briefs of the parties were filed with the Kentucky Commission in October 1999. KIUC's position called for annual revenue reductions for LG&E of $69.6 million.
In January 2000, the Kentucky Commission issued an Order for LG&E in the subject cases. The Kentucky Commission ruled that LG&E should reduce base rates by $27.2 million effective with bills rendered beginning March 1, 2000. The Kentucky Commission eliminated the proposal to operate under its PBR plan and reinstated the fuel adjustment clause mechanism effective March 1, 2000. The Kentucky Commission offered LG&E the opportunity to operate under an ESM for the next three years. Under this mechanism, incremental annual earnings resulting in a rate of return either above or below a range of 10.5% to 12.5% would be shared 60% with shareholders and 40% with ratepayers.
Later in January 2000, LG&E filed motions for correction to the January 2000 orders for computational and other errors made in the Kentucky Commission's orders which produced overstatements in the base rate reductions to LG&E of $1.1 million. LG&E also filed motions for reconsideration with the Kentucky Commission on a number of items in the case in late January. Certain intervening parties in the proceedings have also filed motions for reconsideration asserting, among other things, that the Kentucky Commission understated the amount of base rate reductions.
Other Rate Matters. LG&E's rates contain a DSM provision. The provision includes a rate mechanism that provides concurrent recovery of DSM costs and provides an incentive for implementing DSM programs. This program had allowed LG&E to recover revenues from lost sales associated with the DSM program (decoupling), but in 1998, LG&E and customer interest groups requested an end to the decoupling rate mechanism. In September 1998, the Kentucky Commission accepted LG&E's modified tariff discontinuing the decoupling mechanism effective as of June 1, 1998.
Since October 1997, LG&E has implemented an experimental performance-based ratemaking mechanism related to gas procurement activities and off-system gas sales only. During the three-year test period beginning October 1997, rate adjustments related to this mechanism will be determined for each 12-month period beginning November 1 and ending October 31. During the first two years of the mechanism ended October 31, 1999 and 1998, LG&E recorded $2.2 million and $3.5 million, respectively, for its share of reduced gas costs. These amounts are billed to customers through the gas supply clause.
Prior to implementation of the PBR in July 1999, and following its termination in March 2000, LG&E employed a FAC mechanism, which under Kentucky law allowed LG&E to recover from customers, the actual fuel costs associated with retail electric sales. In February 1999, LG&E received orders from the Kentucky Commission requiring a refund to retail electric customers of approximately $3.9 million resulting from reviews of the FAC from November 1994 through April 1998, of which $1.9 million was refunded in April 1999 for the period beginning November 1994 and ending October 1996. The orders changed LG&E's method of computing fuel costs associated with electric line losses on off-system sales appropriate for recovery through the FAC. LG&E requested that the Kentucky Commission grant rehearing on the February orders, and further requested that the Kentucky Commission stay the refund requirement until it could rule on the rehearing request. The Kentucky Commission granted the request for a stay, and in March 1999 granted rehearing on the appropriate line loss factor associated with off-system sales for the 18-month period ended April 1998. The Kentucky Commission also granted rehearing on the KIUC's request for rehearing on the Kentucky Commission's determination that it lacked authority to require LG&E to pay interest on the refund amounts. The Kentucky Commission conducted a hearing on the rehearing issues and issued a final ruling in December 1999. The Kentucky Commission agreed with LG&E 's position on the appropriate loss factor to use in the FAC computation and reduced the refund level for the 18-month period under review to approximately $800,000. LG&E implemented the refund with billings in the month of January 2000. LG&E has filed an appeal from the Kentucky Commission's February 1999 orders with the Franklin Circuit Court. A decision on the appeals by the Court is expected in 2000.
LG&E intends to file before the end of the first quarter an application with the Kentucky Commission for authority to increase its natural gas rates in order to recoup higher costs for providing natural gas distribution services. LG&E expects implementation before the end of 2000.
Kentucky PSC Administrative Case for Affiliate Transactions. In December 1997, the Kentucky Commission opened Administrative Case No. 369 to consider Kentucky Commission policy regarding cost allocations, affiliate transactions and codes of conduct governing the relationship between utilities and their non-utility operations and affiliates. The Kentucky Commission intends to address two major areas in the proceedings: the tools and conditions needed to prevent cost shifting and cross-subsidization between regulated and non-utility operations; and whether a code of conduct should be established to assure that non-utility segments of the holding company are not engaged in practices that could result in unfair competition caused by cost shifting from the non-utility affiliate to the utility. In September 1998, the Kentucky Commission issued a draft code of conduct and cost allocation guidelines. In January 1999, LG&E, as well as all parties to the proceeding, filed comments on the Kentucky Commission draft proposals. In December 1999, the Kentucky Commission issued guidelines on cost allocation and held a hearing in January 2000, on the draft code of conduct. Management does not expect the ultimate resolution of this matter to have a material adverse effect on LG&E's financial position or results of operations.
Note 4 - Financial Instruments
The cost and estimated fair values of LG&E's non-trading financial instruments as of December 31, 1999 and 1998 follow (in thousands of $):
1999 1998 ---- ---- Fair Fair Cost Value Cost Value ---- ----- ---- -----
Marketable securities $ 7,253 $ 6,936 $ 17,767 $ 17,851 Long-term investments - Not practicable to estimate fair value 746 746 748 748 Preferred stock subject to mandatory redemption 25,000 24,861 25,000 26,413 Long-term debt (including current portion) 626,800 623,498 626,800 648,603 U.S. Treasury note and bond futures -- 81 -- (50) Interest-rate swaps -- 1,666 -- (7,378)
All of the above valuations reflect prices quoted by exchanges except for the swaps and the long-term investments. The fair values of the swaps reflect price quotes from dealers or amounts calculated using accepted pricing models. The fair values of the long-term investments reflect cost, since LG&E cannot reasonably estimate fair value.
Interest Rate Swaps. LG&E enters into interest rate swap agreements to exchange variable interest rate payments obligations without the exchange of underlying principal amounts. As of December 31, 1999 and 1998, LG&E was party to various interest rate swaps with aggregate notional amounts of $234.3 million and $249.3 million, respectively. Under swap agreements LG&E paid fixed rates averaging 3.80% and 3.89% and received variable rates of averaging 5.46% and 4.00% at December 31, 1999 and 1998, respectively. The swaps mature on dates ranging from 2001 to 2020.
At December 31, 1999, LG&E held U.S. Treasury note and bond futures contracts with notional amounts totaling $3.5 million. These contracts are used to hedge price risk associated with certain marketable securities and mature in March 2000.
Note 5 - Concentrations of Credit and Other Risk
Credit risk represents the accounting loss that would be recognized at the reporting date if counterparties failed to perform as contracted. Concentrations of credit risk (whether on- or off-balance sheet) relate to groups of customers or counterparties that have similar economic or industry characteristics that would cause their ability to meet contractual obligations to be similarly affected by changes in economic or other conditions.
LG&E's customer receivables and gas and electric revenues arise from deliveries of natural gas to approximately 295,000 customers and electricity to approximately 366,000 customers in Louisville and adjacent areas in Kentucky. For the year ended December 31, 1999, 82% of total revenue was derived from electric operations and 18% from gas operations.
In December 1998, LG&E and IBEW Local 2100 employees, which represent approximately 60% of LG&E's workforce, entered into a three-year collective bargaining agreement.
Note 6 - Marketable Securities
LG&E's marketable securities have been determined to be "available-for-sale" under the provisions of SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities. Proceeds from sales of available-for-sale securities in 1999 were approximately $11.7 million, which resulted in an immaterial net realized gain, calculated using the specific identification method. Proceeds from sales of available-for-sale securities in 1998 were approximately $18.8 million, which resulted in immaterial realized gains and losses.
Approximate cost, fair value, and other required information pertaining to LG&E's available-for-sale securities by major security type, as of December 31, 1999 and 1998, follow (in thousands of $):
Fixed Equity Income Total ------ ------ ----- 1999: Cost $ 4,385 $ 2,868 $ 7,253 Unrealized gains 90 3 93 Unrealized losses (304) (106) (410) -------- -------- -------- Fair values $ 4,171 $ 2,765 $ 6,936 ======== ======== ========
Fair values: No maturity $ 4,171 $ -- $ 4,171 Contractual maturities: Less than one year -- 2,134 2,134 One to five years -- 631 631 -------- -------- -------- Total fair values $ 4,171 $ 2,765 $ 6,936 ======== ======== ========
1998: Cost $ 3,798 $ 13,969 $ 17,767 Unrealized gains 276 31 307 Unrealized losses (95) (128) (223) -------- -------- -------- Fair values $ 3,979 $ 13,872 $ 17,851 ======== ======== ========
Fair values: No maturity $ 3,979 $ 178 $ 4,157 Contractual maturities: Less than one year -- 8,301 8,301 One to five years -- 3,861 3,861 Over ten years -- 1,532 1,532 -------- -------- -------- Total fair values $ 3,979 $ 13,872 $ 17,851 ======== ======== ========
Note 7 - Pension Plans and Retirement Benefits
Pension Plans. LG&E sponsors several qualified and non-qualified pension plans and other postretirement benefit plans for its employees. The following tables provide a reconciliation of the changes in the plans' benefit obligations and fair value of assets over the three-year period ending December 31, 1999, and a statement of the funded status as of December 31 for each of the last three years (in thousands of $):
1999 1998 1997 ---- ---- ----
Reconciliation of funded status Funded status $(34,471) $(38,902) $(38,989) Unrecognized actuarial (gain) or loss (1,638) (285) 2,901 Unrecognized transition (asset) or obligation 14,489 18,080 20,053 Unrecognized prior service cost 4,292 3,519 3,410 -------- -------- -------- Net amount recognized at end of year $(17,328) $(17,588) $(12,625) ======== ======== ========
There are no plan assets in the nonqualified plan due to the nature of the plan.
The following tables provide the amounts recognized in the balance sheet and information for plans with benefit obligations in excess of plan assets as of December 31, 1999, 1998 and 1997 (in thousands of $):
(1) All years include non-union plan and unfunded SERPs. (2) 1998 includes non-union plan and SERPs. 1999 and 1997 include SERPs only.
Other Benefits: Amounts recognized in the balance sheet consisted of: Accrued benefit liability $(17,328) $(17,588) $(12,625) ======== ======== ========
Additional year-end information for plans with benefit obligations in excess of plan assets: Projected benefit obligation $ 44,997 $ 44,964 $ 43,373 Fair value of plan assets 13,074 6,062 4,384
The following table provides the components of net periodic benefit cost for the plans for 1999, 1998 and 1997 (in thousands of $):
On May 4, 1998, LG&E Energy and KU Energy merged, with LG&E Energy as the surviving corporation. During 1998, LG&E invested approximately $18 million in special termination benefits as a result of its early retirement program offered to eligible employees post-merger.
The assumptions used in the measurement of LG&E's pension benefit obligation are shown in the following table:
For measurement purposes, a 7.00% annual increase in the per capita cost of covered health care benefits was assumed for 2000. The rate was assumed to decrease gradually to 4.75% for 2005 and remain at that level thereafter.
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A 1% change in assumed health care cost trend rates would have the following effects (in thousands of $):
Thrift Savings Plans. LG&E has a thrift savings plan under section 401(k) of the Internal Revenue Code. Under the plan, eligible employees may defer and contribute to the plan a portion of current compensation in order to provide future retirement benefits. LG&E makes contributions to the plan by matching a portion of the employee contributions. The costs were approximately $2.7 million, $2.4 million, and $1.8 million for 1999, 1998, and 1997, respectively.
Note 8 - Income Taxes
Components of income tax expense are shown in the table below (in thousands of $):
1999 1998 1997 ---- ---- ----
Included in operating expenses: Current - federal $53,981 $45,716 $57,590 - state 13,680 11,895 14,593 Deferred - federal - net (4,818) 2,276 (4,565) - state - net (780) 678 703 Deferred investment tax credit -- 55 102 Amortization of investment tax credit (4,289) (4,313) (4,342) ------- ------- ------- Total 57,774 56,307 64,081 ------- ------- -------
Included in other income and (deductions): Current - federal 217 660 1,484 - federal - merger costs -- (6,758) -- - state (30) 6 161 - state - merger costs -- (1,737) -- Deferred - federal - net 254 (165) 292 - state - net 65 (42) 75 ------- ------- ------- Total 506 (8,036) 2,012 ------- ------- -------
Total income tax expense $58,280 $48,271 $66,093 ======= ======= =======
Net deferred tax liabilities resulting from book-tax temporary differences are shown below (in thousands of $):
1999 1998 ---- ----
Deferred tax liabilities: Depreciation and other plant-related items $321,889 $323,869 Other liabilities 5,324 9,644 -------- -------- 327,213 333,513 -------- --------
Deferred tax assets: Investment tax credit 27,145 28,876 Income taxes due to customers 22,588 25,447 Pension overfunding 2,193 2,099 Accrued liabilities not currently deductible and other 19,377 22,502 -------- -------- 71,303 78,924 -------- --------
Net deferred income tax liability $255,910 $254,589 ======== ========
A reconciliation of differences between the statutory U.S. federal income tax rate and LG&E's effective income tax rate follows:
Note 9 - Other Income and Deductions
Other income and deductions consisted of the following at December 31 (in thousands of $):
1999 1998 1997 ---- ---- 2----
Interest and dividend income $ 4,086 $ 4,245 $ 4,786 Interest on income tax settlement -- -- 1,446 Gain on sale of stock options -- -- 1,794 Gains (losses) on fixed asset disposal 2,394 530 77 Donations (102) (168) (147) Income taxes and other (2,237) (2,111) (3,679) Income tax benefit on merger costs -- 8,495 -- ------- -------- -------
Total other income and deductions $ 4,141 $ 10,991 $ 4,277 ======= ======== =======
Note 10 - First Mortgage Bonds and Pollution Control Bonds
Long-term debt and the current portion of long-term debt, summarized below (in thousands of $), consists primarily of first mortgage bonds and pollution control bonds. Interest rates and maturities in the table below are for the amounts outstanding at December 31, 1999.
Under the provisions for LG&E's variable-rate pollution control bonds, the bonds are subject to tender for purchase at the option of the holder and to mandatory tender for purchase upon the occurrence of certain events, causing the bonds to be classified as current portion of long-term debt. The average annualized interest rate for these bonds were 3.98%.
Maturities of LG&E's first mortgage bonds and pollution control bonds (principal amounts stated in thousands of $) at December 31, 1999, are summarized below.
2001 $ -- 2002 20,000 2003 42,600 2004 -- 2005 -- Thereafter 318,000 -------- Total $380,600 ========
In December 1999, LG&E notified bondholders of its intent to exercise its call option on its $20.0 million 7.50% First Mortgage Bonds due July 1, 2002. The bonds were redeemed in January 2000 utilizing proceeds from issuance of commercial paper.
In June 1998, $20 million of LG&E's First Mortgage Bonds matured and were retired.
Annual requirements for the sinking funds of LG&E's First Mortgage Bonds (other than the First Mortgage Bonds issued in connection with certain Pollution Control Bonds) are the amounts necessary to redeem 1% of the highest principal amount of each series of bonds at any time outstanding. Property additions (166 2/3% of principal amounts of bonds otherwise required to be so redeemed) have been applied in lieu of cash.
Substantially all of LG&E's utility plants are pledged as security for its first mortgage bonds. LG&E's indenture, as supplemented, provides in substance that, under certain specified conditions, portions of retained earnings will not be available for the payment of dividends on common stock. No portion of retained earnings is presently restricted by this provision.
Note 11 - Notes Payable
LG&E's short-term financing requirements are satisfied through the sale of commercial paper. LG&E had outstanding commercial paper of $120.1 million at December 31, 1999, at a weighted-average interest rate of
6.02%. LG&E had no short-term borrowings at December 31, 1998.
At December 31, 1999, LG&E had unused lines of credit of $200 million, for which it pays commitment fees. The credit facility provides support of commercial paper borrowings. The credit lines are scheduled to expire in 2001. Management expects to renegotiate these lines when they expire.
Note 12 - Commitments and Contingencies
Construction Program. LG&E had commitments in connection with its construction program aggregating approximately $14.5 million at December 31, 1999. Construction expenditures for the years 2000 and 2001 are estimated to total approximately $401 million.
Operating Lease. LG&E leases office space and accounts for all of its office space leases as operating leases. Total lease expense for 1999, 1998, and 1997, less amounts contributed by the parent company, was $1.5 million, $1.6 million, and $1.8 million, respectively. The future minimum annual lease payments under lease agreements for years subsequent to December 31, 1999, are as follows (in thousands of $):
2000 $ 3,321 2001 3,654 2002 3,594 2003 3,507 2004 3,507 Thereafter 1,754 ------- Total $19,337 =======
In December 1999, LG&E and KU entered into an 18-year cross-border lease of its two jointly owned combustion turbines recently installed at KU's Brown facility. LG&E's obligation was defeased upon consummation of the cross-border lease. The transaction produced a pre-tax gain of approximately $1.2 million which has been deferred pending resolution of rate treatment by the Kentucky Commission.
Environmental. The Act imposed stringent new SO2 and NOx emission limits on electric generating units. LG&E previously had installed scrubbers on all of its generating units. LG&E's strategy for Phase II, commencing January 1, 2000, is to use accumulated emissions allowances to delay additional capital expenditures and may also include fuel switching or the installation of additional scrubbers. LG&E met the NOx emission requirements of the Act through installation of low-NOx burner systems. LG&E's compliance plans are subject to many factors including developments in the emission allowance and fuel markets, future regulatory and legislative initiatives, and advances in clean air control technology. LG&E will continue to monitor these developments to ensure that its environmental obligations are met in the most efficient and cost-effective manner.
In September 1998, the EPA announced its final "NOx SIP call" rule requiring significant additional reductions in NOx emissions by May 2003, in order to mitigate alleged ozone transport to the Northeast. While each of the 22 states covered by the rule is free to allocate its assigned NOx reductions among various emissions sectors as it deems appropriate, the regulation may ultimately require electric generating units to reduce their NOx emissions to 0.15 lb./Mmbtu - an 85% reduction from 1990 levels. In related proceedings in response to petitions filed by various Northeast states, in December 1999, EPA issued a final rule directing similar NOx reductions from a number of specifically named electric generating units including all LG&E stations. Several states, various labor and industry groups, and individual companies have appealed both EPA rulings to the U.S. Court of Appeals for the Washington D.C. Circuit. Management is currently unable to determine the outcome or exact impact of this matter until such time as the courts rule on the pending legal challenges and the states
implement the final regulatory mandate. However, if the 0.15 lb. target is ultimately imposed, LG&E will be required to incur significant capital expenditures and increased operation and maintenance costs for additional controls.
Subject to further study, analysis, and the outcome of pending litigation against the EPA, LG&E estimates that it may incur capital costs for NOx compliance ranging from $65 million to reduce emissions to the level of 0.25 lb./Mmbtu (Commonwealth of Kentucky's proposed NOx compliance level) to $165 million to reduce emissions to the level of 0.15 lb./Mmbtu (current EPA regulations). These costs would generally be incurred beginning in 2000. LG&E believes its costs in this regard to be comparable to those of similarly situated utilities with like generation assets. LG&E anticipates that such capital and operating costs are the type of costs that are eligible for recovery from customers under their environmental surcharge mechanisms and believe that a significant portion of such costs could be recovered. However, Kentucky Commission approval is necessary and there can be no guarantee of recovery.
LG&E is also addressing other air quality issues. First, LG&E is monitoring the status of EPA's revised NAAQS for ozone and particulate matter. In May 1999, the Washington D.C. Circuit remanded the final rule and directed EPA to undertake additional rulemaking efforts. LG&E continues to monitor EPA actions to challenge that ruling. Second, LG&E was notified by regulatory agencies that the Cane Run Station may be the source of a potential exceedance of the NAAQS that could require LG&E to incur additional capital expenditures or accept certain emissions limitations. After reviewing additional modeling information submitted by LG&E, in January 2000, EPA concluded that the Cane Run Station does not contribute to any potential NAAQS exceedance and that no further action is required from LG&E. Third, LG&E is working with regulatory authorities to review the effectiveness of remedial measures aimed at controlling particulate emissions from its Mill Creek Station. LG&E previously settled a number of property damage claims from adjacent residents and completed significant plant modifications as part of its ongoing capital construction program.
LG&E owns or formerly owned three properties which contained past MGP operations. Various contaminants are typically found at such former MGP sites and environmental remediation measures are frequently required. LG&E has reached agreements for other parties to assume cleanup responsibility for two sites it formerly owned. In addition, LG&E recently reached an agreement with the Kentucky Division of Waste Management with respect to a third LG&E-owned site in which LG&E committed to impose certain property restrictions and conduct additional monitoring in lieu of a cleanup. Based on currently available information, management estimates that it will incur additional MGP costs of less than $500,000. Accordingly, an accrual of $500,000 has been recorded in the accompanying financial statements.
Note 13 - Jointly Owned Electric Utility Plant
LG&E owns a 75% undivided interest in Trimble County Unit 1. Accounting for the 75% portion of the Unit, which the Kentucky Commission has allowed to be reflected in customer rates, is similar to LG&E's accounting for other wholly owned utility plants.
Of the remaining 25% of the Unit, IMEA owns a 12.12% undivided interest, and IMPA owns a 12.88% undivided interest. Each is responsible for its proportionate ownership share of fuel cost, operation and maintenance expenses, and incremental assets.
The following data represent shares of the jointly owned property:
Trimble County LG&E IMPA IMEA Total ---- ---- ---- ----- Ownership interest 75% 12.88% 12.12% 100% Mw capacity 371.25 63.75 60.00 495.00
(in thousands of $): Cost $546,497 Accumulated depreciation 140,972 --------- Net book value $405,525 =========
Construction work in progress (included above) $673
In July 1999, following approval from the Kentucky Commission, LG&E purchased for $45.7 million a 38% interest in two 164.5 Mw natural gas turbines installed at KU's E.W. Brown facility (Units 6 and 7) from Capital Corp.
Note 14 - Segments of Business and Related Information
Effective December 31, 1998, LG&E adopted SFAS No. 131, Disclosure About Segments of an Enterprise and Related Information. LG&E is a regulated public utility engaged in the generation, transmission, distribution, and sale of electricity and the storage, distribution, and sale of natural gas. Financial data for business segments, follow (in thousands of $):
Electric Gas Total -------- --- -----
Operating revenues $ 790,670(a) $ 177,579 $ 968,249 Depreciation and amortization 83,619 13,602 97,221 Interest income 3,435 651 4,086 Interest expense 31,558 6,404 37,962 Operating income taxes 56,883 891 57,774 Net income 104,853 1,417 106,270 Total assets 1,775,498 395,954 2,171,452 Construction expenditures 160,844 33,800 194,644
Operating revenues $ 658,511(b) $ 191,545 $ 850,056 Depreciation and amortization 79,866 13,312 93,178 Interest income 3,566 679 4,245 Interest expense 30,389 5,933 36,322 Merger costs 32,072 -- 32,072 Operating income taxes 56,401 (94) 56,307 Net income 75,368 2,752 78,120 Total assets 1,727,463 377,174 2,104,637 Construction expenditures 105,836 32,509 138,345
Electric Gas Total -------- --- -----
Operating revenues $ 614,532 $231,011 $ 845,543 Depreciation and amortization 79,958 13,062 93,020 Interest income 5,279 953 6,232 Interest expense 33,349 5,841 39,190 Operating income taxes 59,415 4,666 64,081 Net income 108,236 5,037 113,273 Total assets 1,677,278 378,363 2,055,641 Construction expenditures 81,713 29,180 110,893
(a) Net of provision for rate refund of $1.7 million. (b) Net of provision for rate refund of $4.5 million.
Note 15 - Selected Quarterly Data (Unaudited)
Selected financial data for the four quarters of 1999 and 1998 are shown below. Because of seasonal fluctuations in temperature and other factors, results for quarters may fluctuate throughout the year.
Quarters Ended March June September December ----- ---- --------- -------- (Thousands of $)
Operating revenues $226,620 $ 214,097 $296,395 $231,137 Net operating income 27,016 30,596 51,036 31,443 Net income 18,916 22,040 41,704 23,610 Net income available for common stock 17,826 20,954(a) 40,614 22,375(b)
Operating revenues $233,344 $ 201,389 $229,885 $185,438 Net operating income 32,326 33,629 53,420 16,148 Net income 23,399 21 44,861 9,839 Net income (loss) available for common stock 22,276 (1,122) 43,726 8,672
(a) The increase of $22.1 million compared to June 1998 was due to a non-recurring after-tax charge of $23.6 million from merger-related expenses.
(b) The increase of $13.7 million compared to December 1998 was primarily due to a non-recurring charge to refund certain amounts collected under the ECR and colder weather in 1999.
Note 16 - Subsequent Events
On February 28, 2000, LG&E Energy announced that its Board of Directors accepted an offer to be acquired by PowerGen for cash of approximately $3.2 billion or $24.85 per share and the assumption of $2.2 billion of LG&E Energy's debt. Pursuant to the acquisition agreement, among other things, LG&E Energy will become a wholly owned subsidiary of PowerGen and its U.S. headquarters. The Utility Operations of the Company will continue their separate identities and serve customers in Kentucky and Virginia under their present names. The preferred stock and debt securities of the Utility Operations will not be affected by this transaction resulting in the Utility Operations' obligation to continue to file SEC reports. The acquisition is expected to close 9 to 12 months from the announcement,
shortly after all of the conditions to consummation of the acquisition are met. Those conditions include, without limitation, the approval of the holders of a majority of the outstanding shares of common stock of each of LG&E Energy and PowerGen, the receipt of all necessary governmental approvals and the making of all necessary governmental filings, including approvals of various regulators in Kentucky and Virginia under state utility laws, the approval of the FERC under the Federal Power Act, the approval of the SEC under the Public Utility Holding Company Act of 1935, and the filing of requisite notifications with the Federal Trade Commission and the Department of Justice under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, and the expiration of all applicable waiting periods thereunder. Shareholder meetings to vote upon the approval of the acquisition are expected to be held during the second quarter of 2000 for both LG&E Energy and PowerGen. During the first quarter of 2000, the Company expensed approximately $1.0 million relating to the PowerGen transaction. The foregoing description of the acquisition does not purport to be complete and is qualified in its entirety by reference to LG&E Energy's current reports on Form 8-K, filed February 29, 2000, with the SEC.
On March 3, 2000, the U.S. Court of Appeals for the Washington D.C. Circuit issued a final opinion upholding the NOx SIP call rule requiring electric generating units to reduce their NOx emissions to 0.15 lb./Mmbtu by May 2003. Some of the litigants will likely seek further judicial review of the ruling.
In the first quarter of 2000, LG&E will take a restructuring charge relating to the reduction of positions and the integration of LG&E's and KU's operations, including combining retail gas and electric operations, consolidation of customer service centers and the redesigning various other processes.
The Kentucky Commission responded to the motions filed by LG&E for computational and other errors made in Orders received on base rate reductions in February 2000 by granting rehearings for LG&E on various issues.
Louisville Gas and Electric Company REPORT OF MANAGEMENT
The management of Louisville Gas and Electric Company is responsible for the preparation and integrity of the financial statements and related information included in this Annual Report. These statements have been prepared in accordance with generally accepted accounting principles applied on a consistent basis and, necessarily, include amounts that reflect the best estimates and judgment of management.
LG&E's financial statements have been audited by Arthur Andersen LLP, independent public accountants. Management has made available to Arthur Andersen LLP all LG&E's financial records and related data as well as the minutes of shareholders' and directors' meetings. Management has established and maintains a system of internal controls that provides reasonable assurance that transactions are completed in accordance with management's authorization, that assets are safeguarded and that financial statements are prepared in conformity with generally accepted accounting principles. Management believes that an adequate system of internal controls is maintained through the selection and training of personnel, appropriate division of responsibility, establishment and communication of policies and procedures and by regular reviews of internal accounting controls by LG&E's internal auditors. Management reviews and modifies its system of internal controls in light of changes in conditions and operations, as well as in response to recommendations from the internal auditors. These recommendations for the year ended December 31, 1999, did not identify any material weaknesses in the design and operation of LG&E's internal control structure.
The Audit Committee of the Board of Directors is composed entirely of outside directors. In carrying out its oversight role for the financial reporting and internal controls of LG&E, the Audit Committee meets regularly with LG&E's independent public accountants, internal auditors and management. The Audit Committee reviews the results of the independent accountants' audit of the financial statements and their audit procedures, and discusses the adequacy of internal accounting controls. The Audit Committee also approves the annual internal auditing program and reviews the activities and results of the internal auditing function. Both the independent public accountants and the internal auditors have access to the Audit Committee at any time.
Louisville Gas and Electric Company maintains and internally communicates a written code of business conduct that addresses, among other items, potential conflicts of interest, compliance with laws, including those relating to financial disclosure and the confidentiality of proprietary information.
Louisville Gas and Electric Company REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders of Louisville Gas and Electric Company:
We have audited the accompanying balance sheets and statements of capitalization of Louisville Gas and Electric Company (a Kentucky corporation and a wholly-owned subsidiary of LG&E Energy Corp.) as of December 31, 1999 and 1998, and the related statements of income, retained earnings, cash flows and comprehensive income for each of the three years in the period ended December 31, 1999. These financial statements are the responsibility of LG&E's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Louisville Gas and Electric Company as of December 31, 1999 and 1998, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1999, in conformity with accounting principles generally accepted in the United States.
Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule listed under Item 14(a)2 is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audit of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
Louisville, Kentucky Arthur Andersen LLP January 26, 2000 (Except with respect to the matters discussed in Note 16, as to which the date is March 3, 2000.)
Kentucky Utilities Company Statements of Income (Thousands of $)
Statements of Retained Earnings (Thousands of $)
The accompanying notes are an integral part of these financial statements.
Kentucky Utilities Company Balance Sheets (Thousands of $)
The accompanying notes are an integral part of these financial statements.
Kentucky Utilities Company Statements of Cash Flows (Thousands of $)
The accompanying notes are an integral part of these financial statements.
Kentucky Utilities Company Statements of Capitalization (Thousands of $)
December 31 1999 1998 ---- ----
COMMON EQUITY: Common stock, without par value - outstanding 37,817,878 shares ......... $ 308,140 $ 308,140 Retained earnings ........................ 329,470 299,168 Other .................................... (595) (595) --------- ---------
637,015 606,713 --------- ---------
CUMULATIVE PREFERRED STOCK: Cumulative and redeemable on 30 days notice by KU:
The accompanying notes are an integral part of these financial statements.
Kentucky Utilities Company Notes to Financial Statements
Note 1 - Summary of Significant Accounting Policies
KU is a subsidiary of LG&E Energy. KU is a regulated public utility that is engaged in the generation, transmission, distribution, and sale of electric energy. LG&E Energy is an exempt energy services holding company with wholly-owned subsidiaries consisting of LG&E, KU, Capital Corp., and LEM. All of the KU's Common Stock is held by LG&E Energy.
Certain reclassification entries have been made to the 1998 and 1997 financial statements to conform to the 1999 presentation with no impact on previously reported net income.
Cash and Temporary Cash Investments. KU considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. Temporary cash investments are carried at cost, which approximates fair value.
Utility Plant. KU's utility plant is stated at original cost, which includes payroll-related costs such as taxes, fringe benefits, and administrative and general costs. Construction work in progress has been included in the rate base for determining retail customer rates. KU has not recorded any allowance for funds used during construction.
The cost of plant retired or disposed of in the normal course of business is deducted from plant accounts and such cost, plus removal expense less salvage value, is charged to the reserve for depreciation. When complete operating units are disposed of, appropriate adjustments are made to the reserve for depreciation and gains and losses, if any, are recognized.
Depreciation and amortization. Depreciation is provided on the straight-line method over the estimated service lives of depreciable plant. The amounts provided for KU approximated 3.5% in 1999, 1998 and 1997.
Financial Instruments. KU uses over-the-counter interest-rate swap agreements to hedge its exposure to interest rates. Gains and losses on interest-rate swaps used to hedge interest rate risk are reflected in interest charges monthly. See Note 4, Financial Instruments.
Debt Expense. Debt expense is amortized over the lives of the related bond issues, consistent with regulatory practices.
Deferred Income Taxes. Deferred income taxes have been provided for all material book-tax temporary differences.
Investment Tax Credits. Investment tax credits resulted from provisions of the tax law that permitted a reduction of KU's tax liability based on credits for certain construction expenditures. Deferred investment tax credits are being amortized to income over the estimated lives of the related property that gave rise to the credits.
Revenue Recognition. Revenues are recorded based on service rendered to customers through month-end. KU accrues an estimate for unbilled revenues from each meter reading date to the end of the accounting period. The unbilled revenue estimates included in accounts receivable for KU equaled approximately $29.6 million at December 31, 1999 and 1998.
Fuel Costs. The cost of fuel for electric generation is charged to expense as used.
Management's Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported assets and liabilities and disclosure of contingent items at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. See Note 11, Commitments and Contingencies, for a further discussion.
New Accounting Pronouncements. During 1999 and 1998, the following accounting pronouncements were issued that affect KU:
SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or a liability measured at its fair value. SFAS No. 133 requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and requires that KU must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. KU has not yet quantified all the effects of adopting SFAS No. 133 on the financial statements. However, SFAS No. 133 could increase the volatility in earnings and other comprehensive income. The effect of this statement will be recorded in cumulative effect of change in accounting when adopted. SFAS No. 137, Accounting for Derivative Instruments and Hedging Activities -- Deferral of the Effective Date of SFAS No. 133, deferred the effective date of SFAS No. 133 until January 1, 2001.
EITF No. 98-10, Accounting for Energy Trading and Risk Management Activities was adopted effective January 1, 1999. The pronouncement requires that energy trading contracts to be marked to market on the balance sheet, with the gains and losses shown net in the income statement. EITF No. 98-10 more broadly defines what represents energy trading to include economic activities related to physical assets which were not previously marked to market by established industry practice. Adoption of EITF No. 98-10 did not have a material impact on KU's results of operations or financial position.
SOP 98-1, Accounting for the Costs of Computer Software Developed or Obtained for Internal Use. Adopted as of January 1, 1998, SOP 98-1 clarifies the criteria for capital or expense treatment of costs incurred by an enterprise to develop or obtain computer software to be used in its internal operations. The statement does not change treatment of costs incurred in connection with correcting computer programs to properly process the millennium change to the Year 2000, which were expensed as incurred. Adoption of SOP 98-1 did not have a material effect on KU's financial statements.
Note 2 - LG&E - Kentucky Utilities Merger
LG&E Energy and KU Energy merged on May 4, 1998, with LG&E Energy as the surviving corporation. As a result of the merger, the LG&E Energy, which is the parent of LG&E, became the parent company of KU. The operating utility subsidiaries (LG&E and KU) have continued to maintain their separate corporate identities and serve customers in Kentucky and Virginia under their present names. LG&E Energy has estimated approximately $760 million in gross non-fuel savings over a ten-year period following the merger. Costs to achieve these savings for KU of $42.3 million were recorded in the second quarter of 1998, $20.5 million of which were initially deferred and are being amortized over a five-year period pursuant to regulatory orders. Primary components of the merger costs were separation benefits, relocation costs, and transaction fees, the majority of which were paid by December 31, 1998. KU expensed the remaining costs associated with the merger ($21.8 million) at the time of the merger in the second quarter of 1998. In regulatory filings associated with approval of the merger, KU committed not to seek increases in existing base rates and proposed reductions in their retail customers' bills in amounts based on one-half of the savings, net of the deferred and amortized amount, over a
five-year period. The preferred stock and debt securities of KU were not affected by the merger.
LG&E Energy, as the parent of LG&E and KU, continues to be an exempt holding company under PUHCA. Management has accounted for the merger as a pooling of interests and as a tax-free reorganization under the Internal Revenue Code.
In the application filed with the Kentucky Commission, the utilities proposed that 50% of the net non-fuel cost savings estimated to be achieved from the merger, less $38.6 million or 50% of the originally estimated costs to achieve such savings, be applied to reduce customer rates through a surcredit on customers' bills and the remaining 50% be retained by the companies. The Kentucky Commission approved the surcredit and allocated the customer savings 53% to KU and 47% to LG&E. The surcredit will be about 2% of customer bills over the next five years and will amount to approximately $63 million in net non-fuel savings to KU. Any fuel cost savings are passed to Kentucky customers through the companies' fuel adjustment clauses. See Note 3 for more information about KU's rates and regulatory matters.
Note 3 - Utility Rates and Regulatory Matters
Accounting for the regulated utility business conforms with generally accepted accounting principles as applied to regulated public utilities and as prescribed by FERC, the Kentucky Commission and the Virginia Commission. KU is subject to SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. Under SFAS No. 71, certain costs that would otherwise be charged to expense are deferred as regulatory assets based on expected recovery from customers in future rates. Likewise, certain credits that would otherwise be reflected as income are deferred as regulatory liabilities based on expected flowback to customers in future rates. KU's current or expected recovery of deferred costs and expected flowback of deferred credits is generally based on specific ratemaking decisions or precedent for each item. The following regulatory assets and liabilities were included in KU's balance sheets as of December 31 (in thousands of $):
1999 1998 ---- ----
Unamortized loss on bonds $ 7,594 $ 8,675 Merger costs 14,324 18,417 Other 1,115 1,136 -------- -------- Total regulatory assets 23,033 28,228 -------- --------
Deferred income taxes - net (42,992) (45,882) Other (3,077) (670) -------- -------- Total regulatory liabilities (46,069) (46,552) -------- --------
Regulatory liabilities - net $(23,036) $(18,324) ======== ========
Environmental Cost Recovery. In August 1994 KU implemented an ECR surcharge. The Kentucky Commission's order approving the surcharge for KU as well as the constitutionality of the surcharge was challenged by certain intervenors in Franklin Circuit Court. Decisions of the Circuit Court and the Kentucky Court of Appeals in July 1995 and December 1997, respectively, upheld the constitutionality of the ECR statute but differed on a claim of retroactive recovery of certain amounts. Based on these decisions, the Kentucky Commission ordered that certain surcharge revenues collected by KU be subject to refund pending final determination of all appeals.
In December 1998, the Kentucky Supreme Court rendered an opinion upholding the constitutionality of the surcharge statute but denied recovery of costs associated with pre-1993 environmental projects through the ECR. The court remanded the case to the Kentucky Commission to determine amounts to be refunded for
revenues collected for such pre-1993 environmental projects. Accordingly, KU recorded a provision for rate refund of $21.5 million in December 1998.
The parties to the proceedings reached a settlement agreement that was approved in a Final Order issued by the Kentucky Commission in August 1999. This Final Order resulted in the reversal of approximately $1.5 million of the provision for rate refunds established by KU in December 1998. The refund is being applied to customers' bills during the twelve-month period beginning October 1999.
Future Rate Regulation. In October 1998, KU filed an application with the Kentucky Commission for approval of a new method of determining electric rates that sought to provide financial incentives for KU to further reduce customers' rates. The filing was made pursuant to the September 1997 Kentucky Commission order approving the merger of LG&E Energy and KU Energy, wherein the Kentucky Commission directed LG&E and KU to indicate whether they desired to remain under traditional rate of return regulation or commence non-traditional regulation. The proposed ratemaking method, known as PBR, included financial incentives for KU to reduce fuel costs and increase generating efficiency, and to share any resulting savings with customers. Additionally, the PBR proposal provided for financial penalties and rewards to assure continued high quality service and reliability.
In April 1999, KU filed a joint agreement with LG&E and the Kentucky Attorney General to adopt the PBR plan subject to certain amendments. The amended filing included requested Kentucky Commission approval of a five-year rate reduction plan which proposed to reduce the electric rates of KU by $10.6 million in the first year (beginning July 1999), and by $4.2 million annually through June 2004. The proposed amended plan also included establishment by KU of a $3.2 million program for low-income customer assistance as well as extension for one additional year of both the rate cap proposal and merger savings surcredit established in the original merger plan of LG&E and KU. Under the rate cap proposal KU agreed, in the absence of extraordinary circumstances, not to increase base electric rates for five years following the merger and LG&E also agreed to refrain from filing for an increase in natural gas rates through June 2004.
In April 1999, the Kentucky Commission issued initial orders implementing the amended PBR plan, effective July 1999, and subject to modification. The Kentucky Commission also consolidated into the continuing PBR proceedings an earlier March 1999, rate complaint by a group of industrial intervenors, KIUC, in which KIUC requested significant reductions in electric rates. Hearings were conducted before the Kentucky Commission on LG&E's and KU's amended PBR plans and the KIUC rate reduction petitions in August and September 1999. Legal briefs of the parties were filed with the Kentucky Commission in October 1999. KIUC's position called for annual revenue reductions for KU of $61.5 million.
In January 2000, the Kentucky Commission issued Orders for KU in the subject cases. The Kentucky Commission ruled that KU should reduce base rates by $36.5 million effective with bills rendered beginning March 1, 2000. The Kentucky Commission eliminated proposal to operate under its PBR plan and reinstated the FAC mechanism effective March 1, 2000. The Kentucky Commission offered KU the opportunity to operate under an ESM for the next three years. Under this mechanism, incremental annual earnings for each utility resulting in a rate of return either above or below a range of 10.5% to 12.5% would be shared 60% with shareholders and 40% with ratepayers.
Later in January 2000, KU filed motions for correction to the January 2000 orders for computational and other errors made in the Kentucky Commission's orders which produced overstatements in the base rate reductions to KU of $7.7 million. KU also filed motions for reconsideration with the Kentucky Commission on a number of items in the case in late January. Certain intervening parties in the proceedings have also filed motions for reconsideration asserting, among other things, that the Kentucky Commission understated the amount of base rate reductions.
Other Rate Matters. Prior to implementation of the PBR in July 1999, and following its termination in March 2000, KU employed an FAC mechanism, which under Kentucky law allowed the utilities to recover from customers the actual fuel costs associated with retail electric sales.
In July 1999, the Kentucky Commission issued a series of orders requiring KU to refund approximately $10.1 million resulting from reviews of the FAC from November 1994 to October 1998. The orders changed KU's method of computing fuel costs associated with electric line losses on off-system sales appropriate for recovery through the FAC, and KU's method for computing system line losses for the purpose of calculating the system sales component of the FAC charge. At KU's request, in July 1999, the Kentucky Commission stayed the refund requirement pending the Kentucky Commission's final determination of any rehearing request that KU may file. In August 1999, KU filed its request for rehearing of the July orders.
In August 1999, the Kentucky Commission issued a Final Order in the KU proceedings, agreeing, in part, with KU's arguments outlined in its Petition for Rehearing. While the Kentucky Commission confirmed that KU should change its method of computing the fuel costs associated with electric line losses, it agreed with KU that the line loss percentage should be based on KU's actual line losses incurred in making off-system sales rather than the percentage used in its Open Access Transmission Tariff. The Kentucky Commission also upheld its previous ruling concerning the computation of system line losses in the calculation of the FAC. The net effect of the Kentucky Commission's Final Order was to reduce the refund obligation to $5.8 million from the original Order amount of $10.1 million. In August 1999, KU recorded its estimated share of anticipated FAC refunds of $7.7 million. KU began implementing the refund in October and will continue the refund through September 2000. Both KU and the KIUC have appealed the Order to the Franklin Circuit Court. A decision is not expected on the appeal until later in 2000.
Kentucky PSC Administrative Case for Affiliate Transactions. In December 1997, the Kentucky Commission opened Administrative Case No. 369 to consider Kentucky Commission policy regarding cost allocations, affiliate transactions and codes of conduct governing the relationship between utilities and their non-utility operations and affiliates. The Kentucky Commission intends to address two major areas in the proceedings: the tools and conditions needed to prevent cost shifting and cross-subsidization between regulated and non-utility operations; and whether a code of conduct should be established to assure that non-utility segments of the holding company are not engaged in practices that could result in unfair competition caused by cost shifting from the non-utility affiliate to the utility. In September 1998, the Kentucky Commission issued a draft code of conduct and cost allocation guidelines. In January 1999, KU, as well as all parties to the proceeding, filed comments on the Kentucky Commission draft proposals. In December 1999, the Kentucky Commission issued guidelines on cost allocation and held a hearing in January 2000, on the draft code of conduct. Management does not expect the ultimate resolution of this matter to have a material adverse effect on the Company's financial position or results of operations.
Note 4 - Financial Instruments
The cost and estimated fair values of the KU's non-trading financial instruments as of December 31, 1999 and 1998 follow (in thousands of $):
1999 1998 ---- ---- Fair Fair Cost Value Cost Value ---- ----- ---- ----- Long-term debt (including current portion) $546,330 $ 542,242 $546,330 $587,245 Interest-rate swaps -- (1,951) -- --
All of the above valuations reflect prices quoted by exchanges except for the swaps. The fair values of the swaps reflect price quotes from dealers or amounts calculated using accepted pricing models.
Interest Rate Swap. KU entered into an interest rate swap agreement to exchange fixed interest rate payment obligations for variable interest rate payments without the exchange of underlying principal amounts. As of December 31, 1999, KU was party to an interest rate swap with a notional amount of $53.0 million. Under the swap agreement KU received a fixed rate of 7.92% and paid a variable rate of 7.90% at December 31, 1999. The swap matures in 2004.
Note 5 - Concentrations of Credit and Other Risk
Credit risk represents the accounting loss that would be recognized at the reporting date if counterparties failed to perform as contracted. Concentrations of credit risk (whether on- or off-balance sheet) relate to groups of customers or counterparties that have similar economic or industry characteristics that would cause their ability to meet contractual obligations to be similarly affected by changes in economic or other conditions.
KU's customer receivables and revenues arise from deliveries of electricity to about 458,000 customers in over 600 communities and adjacent suburban and rural areas in 77 counties in central, southeastern and western Kentucky and to about 29,000 customers in five counties in southwestern Virginia. For the year ended December 31, 1999, 100% of total utility revenue was derived from electric operations.
In August 1999, KU and their employees represented by IBEW Local 101 and USWA Local 8686, which represents approximately 14% of KU's workforce, entered into a one-year collective bargaining agreement.
Note 6 - Pension Plans and Retirement Benefits
Pension Plans. KU sponsors qualified and non-qualified pension plans and other postretirement benefit plans for its employees. The following tables provide a reconciliation of the changes in the plans' benefit obligations and fair value of assets over the three-year period ending December 31, 1999, and a statement of the funded status as of December 31 for each of the last three years (in thousands of $):
There are no plan assets in the non-qualified plan due to the nature of the plan.
The following tables provide the amounts recognized in the balance sheet and information for plans with benefit obligations in excess of plan assets as of December 31, 1999, 1998 and 1997 (in thousands of $):
The following table provides the components of net periodic benefit cost for the plans for 1999, 1998 and 1997 (in thousands of $):
On May 4, 1998 LG&E Energy and KU Energy merged, with LG&E Energy as the surviving corporation. At the time of the merger KU had both qualified and nonqualified pension plans. Under the provisions of the Supplemental Security Plan (SERP), the Merger Agreement constituted a change-in-control which required that a lump sum present value payment be made out of KU's SERP to retired employees entitled to retirement benefits on the date of the Merger Agreement. In May 1997, $4.7 million in lump sum payments were made to these retired employees.
Effective May 4, 1998, due to the change in control, the present value balance of KU's SERP of $4.9 million was transferred and allocated between LG&E Energy's Nonqualified Savings Plan and KU's Nonqualified Savings plan of $2.2 million and $2.7 million, respectively. The plan is an unfunded, pretax deferred compensation program which provides officers and senior managers of KU the opportunity to defer earnings above the qualified savings plan limits. As an "Unfunded" plan the money is not specifically invested or secured and future distributions will be made from the general assets of KU. Currently interest is credited at a rate equal to the average yield on five-year Treasury notes.
During 1998, KU invested approximately $6.6 million in special termination benefits as a result of its early retirement program offered to eligible employees post-merger.
KU provides nonpension postretirement benefits for eligible retired employees.
The assumptions used in the measurement of the KU's benefit obligation are shown in the following table:
1999 1998 1997 ---- ---- ----
Weighted-average assumptions as of December 31: Discount rate 8.00% 7.00% 7.75% Expected long-term rate of return on plan assets 9.50% 8.25% 8.25% Rate of compensation increase 5.00% 4.00% 4.75%
For measurement purposes, a 7.00% annual increase in the per capita cost of covered health care benefits was assumed for 2000. The rate was assumed to decrease gradually to 4.75% for 2005 and remain at that level thereafter.
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A 1% change in assumed health care cost trend rates would have the following effects (in thousands of $):
Thrift Savings Plans. KU has a thrift savings plan under section 401(k) of the Internal Revenue Code. Under the plan, eligible employees may defer and contribute to the plan a portion of current compensation in order to provide future retirement benefits. KU makes contributions to the plan by matching a portion of the employee contributions. The costs of this matching were approximately $2.3 million for 1999 and $2.2 million for each of 1998 and 1997.
Note 7 - Income Taxes
Components of income tax expense are shown in the table below (in thousands of $):
1999 1998 1997 ---- ---- ----
Included in operating expenses: Current - federal $50,969 $46,321 $39,353 - state 13,459 10,245 8,964 Deferred - federal - net (4,833) (3,186) 1,996 - state - net 785 (124) 1,377 ------- ------- ------- Total 60,380 53,256 51,690
Included in other income and (deductions): Current - federal 1,028 (617) (853) - state 54 (237) (246) Deferred - federal - net 182 694 975 - state - net 102 178 258 Amortization of investment tax credit (3,727) (3,829) (4,036) ------- ------- ------- Total (2,361) (3,811) (3,902) ------- ------- -------
Total income tax expense $58,019 $49,445 $47,788 ======= ======= =======
Net deferred tax liabilities resulting from book-tax temporary differences are shown below (in thousands of $):
1999 1998 ---- ---- Deferred tax liabilities: Depreciation and other plant-related items $313,202 $289,147 Other liabilities 11,286 5,598 -------- -------- 324,488 294,745 -------- --------
Deferred tax assets: Investment tax credit 7,497 9,001 Income taxes due to customers 16,712 17,574 Accrued liabilities not currently deductible and other 5,797 6,162 Less: amounts included in current assets 50,862 17,515 -------- -------- 80,868 50,252 -------- --------
Net deferred income tax liability $243,620 $244,493 ======== ========
A reconciliation of differences between the statutory U.S. federal income tax rate and KU's effective income tax rate follows:
1999 1998 1997 ---- ---- ----
Statutory federal income tax rate 35.0% 35.0% 35.0% State income taxes net of federal benefit 5.7 5.4 5.0 Amortization of investment tax credit (2.9) (3.1) (3.0) Nondeductible merger expenses -- 6.4 -- Other differences - net (2.5) (2.2) (1.2) ------ ------ ------
Effective income tax rate 35.3% 41.5% 35.8% ====== ====== ======
Note 8 - Other Income and Deductions
Other income and deductions consisted of the following at December 31 (in thousands of $):
1999 1998 1997 ---- ---- ----
Equity in earnings - subsidiary company $ 2,334 $ 2,167 $ 2,480 Interest and dividend income 4,293 1,811 1,673 Gains (losses) on fixed asset disposal 759 272 412 Donations (107) (453) (388) Income taxes and other 2,158 4,049 2,826 ------- ------- -------
Net other income $ 9,437 $ 7,846 $ 7,003 ======= ======= =======
Note 9 - First Mortgage Bonds and Pollution Control Bonds
Long-term debt and the current portion of long-term debt, summarized below in thousands, consists primarily of first mortgage bonds and pollution control bonds. Interest rates and maturities in the table below are for the amounts outstanding at December 31, 1999.
Stated interest rates 5.75% - 8.55% Weighted-average interest rate 7.02% Maturities 2003 - 2027 Noncurrent portion at December 31, 1999 $430,830 Current portion at December 31, 1999 $115,500
Under the provisions for KU's variable-rate pollution control bonds, the bonds are subject to tender for purchase at the option of the holder and to mandatory tender for purchase upon the occurrence of certain events, causing the bonds to be classified as current portion of long-term debt. The average annualized interest rate for these bonds were 3.35% for KU's bonds.
Maturities of KU's first mortgage bonds and pollution control bonds (principal amounts stated in thousands of $) at December 31, 1999, are summarized below.
2001 $ -- 2003 62,000 2004 -- 2005 -- Thereafter 368,830 -------- Total $430,830 ========
Substantially all of KU's utility plant is pledged as security for its First Mortgage Bonds.
Note 10 - Notes Payable
KU's short-term financing requirements are satisfied through the sale of commercial paper. KU had no short-term borrowings at December 31, 1999, and 1998.
The KU credit facilities that provided for short-term borrowing and support of commercial paper borrowing expired on December 31, 1999.
Note 11 - Commitments and Contingencies
Construction Program. KU had $13.8 million of commitments in connection with its construction program at December 31, 1999. Construction expenditures for the years 2000 and 2001 are estimated to total approximately $324 million.
Operating Leases. KU leases office space, office equipment, and vehicles. KU accounts for these leases as operating leases. Total lease expense for 1999, 1998, and 1997, was $1.7 million, $1.9 million, and $1.8 million, respectively.
In December 1999, LG&E and KU entered into an 18-year cross-border lease of its two jointly owned combustion turbines recently installed at KU's Brown facility. KU's obligation was defeased upon consummation of the cross-border lease. The transaction produced a pre-tax gain of approximately $1.9 million which has
been deferred pending resolution of rate treatment by the Kentucky Commission.
Environmental. The Act imposed stringent new SO2 and NOx emission limits on electric generating units. KU met its Phase I SO2 requirements primarily through installation of a scrubber on Ghent Unit 1. KU's strategy for Phase II, commencing January 1, 2000, is to use accumulated emissions allowances to delay additional capital expenditures and may also include fuel switching or the installation of additional scrubbers. KU met the NOx emission requirements of the Act through installation of low-NOx burner systems. KU's compliance plans are subject to many factors including developments in the emission allowance and fuel markets, future regulatory and legislative initiatives, and advances in clean air control technology. KU will continue to monitor these developments to ensure that its environmental obligations are met in the most efficient and cost-effective manner.
In September 1998, the EPA announced its final "NOx SIP call" rule requiring significant additional reductions in NOx emissions by May 2003, in order to mitigate alleged ozone transport to the Northeast. While each of the 22 states covered by the rule is free to allocate its assigned NOx reductions among various emissions sectors as it deems appropriate, the regulation may ultimately require electric generating units to reduce their NOx emissions to 0.15 lb./Mmbtu - an 85% reduction from 1990 levels. In related proceedings in response to petitions filed by various Northeast states, in December 1999, EPA issued a final rule directing similar NOx reductions from a number of specifically named electric generating units including all KU stations in the eastern half of Kentucky. Additional petitions currently pending before EPA may potentially result in orders encompassing the remaining KU stations. Several states, various labor and industry groups, and individual companies have appealed both EPA rulings to the U.S. Court of Appeals for the Washington D.C. Circuit. Management is currently unable to determine the outcome or exact impact of this matter until such time as the courts rule on the pending legal challenges and the states implement the final regulatory mandate. However, if the 0.15 lb. target is ultimately imposed, KU will be required to incur significant capital expenditures and increased operation and maintenance costs for additional controls.
Subject to further study, analysis, and the outcome of pending litigation against the EPA, KU estimates that it may incur approximate capital costs for NOx compliance ranging from $126 million to reduce emissions to the level of .25 lb./Mmbtu (Commonwealth of Kentucky's proposed NOx compliance level) to $168 million to reduce emissions to the level of .15 lb./Mmbtu (current EPA regulations). These costs would generally be incurred beginning in 2000. KU believes its costs in this regard to be comparable to those of similarly situated utilities with like generation assets. KU anticipates that such capital and operating costs are the type of costs that are eligible for recovery from customers under its environmental surcharge mechanisms and believe that a significant portion of such costs could be recovered. However, Kentucky Commission approval is necessary and there can be no guarantee of recovery.
KU is also addressing other air quality issues. First, KU is monitoring the status of EPA's revised NAAQS for ozone and particulate matter. In May 1999, the Washington D.C. Circuit remanded the final rule and directed EPA to undertake additional rulemaking efforts. KU continues to monitor EPA actions to challenge that ruling.
KU owns or formerly owned several properties which contained past MGP operations. Various contaminants are typically found at such former MGP sites and environmental remediation measures are frequently required. KU has completed the cleanup of a site owned by KU. With respect to other former MGP sites no longer owned by KU, KU is unable to determine what, if any, additional exposure or liability it may have as it lacks complete information on current site conditions.
In October 1999, approximately 38,000 gallons of diesel fuel leaked from a cracked valve in an underground pipeline at KU's E.W. Brown Station. Under the oversight of EPA and state officials, KU commenced immediate spill containment and recovery measures which prevented the spill from reaching the Kentucky
River. KU ultimately recovered approximately 34,000 gallons of diesel fuel. In November 1999, the Kentucky Division of Water issued a notice of violation for the incident. KU is currently negotiating with the state in an effort to reach a complete resolution of this matter. To date KU has incurred costs of approximately $1 million. The Company does not expect to incur any material additional amounts.
Purchased Power. KU has purchase power arrangements with OMU, EEI and other parties. Under the OMU agreement, which expires on January 1, 2020, KU purchases all of the output of a 400-Mw generating station not required by OMU. The amount of purchased power available to KU during 2000-2004, which is expected to be approximately 7% of KU's total kWh requirements, is dependent upon a number of factors including the units' availability, maintenance schedules, fuel costs and OMU requirements. Payments are based on the total costs of the station allocated per terms of the OMU agreement, which generally follows delivered kWh. Included in the total costs is KU's proportionate share of debt service requirements on $172 million of OMU bonds outstanding at December 31, 1999. The debt service is allocated to KU based on its annual allocated share of capacity, which averaged approximately 46% in 1999.
KU has a 20% equity ownership in EEI, which is accounted for on the equity method of accounting. KU's entitlement is 20% of the available capacity of a 1,000 Mw station. Payments are based on the total costs of the station allocated per terms of an agreement among the owners, which generally follows delivered kWh.
KU has several other contracts for purchased power during 2000 - 2004 of various Mw capacities and for varying periods with a maximum entitlement at any time of 62 Mw.
The estimated future minimum annual payments under purchased power agreements for the five years ended December 31, 2004, are as follows (in thousands of $):
2000 $ 28,765 2001 31,495 2002 30,683 2003 30,947 2004 31,155 -------- Total $153,045 ========
Note 12 - Jointly Owned Electric Utility Plant
In July 1999, following approval from the Kentucky Commission, KU purchased for $76.7 million a 62% interest in two 164.5 Mw natural gas turbines installed at the E.W. Brown facility (Units 6 and 7) from Capital Corp.
Note 13 - Selected Quarterly Data (Unaudited)
Selected financial data for the four quarters of 1999 and 1998 are shown below. Because of seasonal fluctuations in temperature and other factors, results for quarters may fluctuate throughout the year.
Quarters Ended March June September December ----- ---- --------- -------- (Thousands of $) - ---- Revenues $217,349 $ 225,794 $281,503 $212,664 Operating income 36,966 34,997 32,529 31,524 Net income 29,628 27,757 24,426 24,747 Net income available for common stock 29,064 27,193(a) 23,862(b) 24,183(c)
- ---- Revenues $183,219 $ 193,079 $246,117 $187,699 Operating income 33,035 28,144 44,677 19,532 Net income (loss) 25,049 (1,119) 36,980 11,854 Net income (loss) available for common stock 24,485 (1,683) 36,416 11,290
(a) The increase of $28.9 million compared to June 1998 was primarily due to a non-recurring after-tax charge of $21.5 million from merger-related expenses.
(b) The decrease of $12.6 million compared to September 1998 was primarily due to a charge to record a net provision for the refund of certain revenues under the FAC and ECR.
(c) The increase of $12.9 million compared to December 1998 was primarily due to a charge to refund certain amounts collected under the ECR.
Note 14 - Subsequent Events
On February 28, 2000, LG&E Energy announced that its Board of Directors accepted an offer to be acquired by PowerGen for cash of approximately $3.2 billion or $24.85 per share and the assumption of $2.2 billion of LG&E Energy's debt. Pursuant to the acquisition agreement, among other things, LG&E Energy will become a wholly owned subsidiary of PowerGen and its U.S. headquarters. The Utility Operations of the Company will continue their separate identities and serve customers in Kentucky and Virginia under their present names. The preferred stock and debt securities of the Utility Operations will not be affected by this transaction resulting in the Utility Operations' obligation to continue to file SEC reports. The acquisition is expected to close 9 to 12 months from the announcement, shortly after all of the conditions to consummation of the acquisition are met. Those conditions include, without limitation, the approval of the holders of a majority of the outstanding shares of common stock of each of LG&E Energy and PowerGen, the receipt of all necessary governmental approvals and the making of all necessary governmental filings, including approvals of various regulators in Kentucky and Virginia under state utility laws, the approval of the Federal Energy Regulatory Commission under the Federal Power Act, the approval of the SEC under the Public Utility Holding Company Act of 1935, and the filing of requisite notifications with the Federal Trade Commission and the Department of Justice under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, and the expiration of all applicable waiting periods thereunder. Shareholder meetings to vote upon the approval of the acquisition are expected to be held during the second quarter of 2000 for both LG&E Energy and PowerGen. During the first quarter of 2000, the Company expensed approximately $1.0 million relating to the PowerGen transaction. The foregoing
description of the acquisition does not purport to be complete and is qualified in its entirety by reference to LG&E Energy's current reports on Form 8-K, filed February 29, 2000, with the SEC.
On March 3, 2000, the U.S. Court of Appeals for the Washington D.C. Circuit issued a final opinion upholding the NOx SIP call rule requiring electric generating units to reduce their NOx emissions to 0.15 lb./Mmbtu by May 2003. Some of the litigants will likely seek further judicial review of the ruling.
In the first quarter of 2000, KU will take a restructuring charge relating to the reduction of positions and the integration of LG&E's and KU's operations, including combining retail gas and electric operations, consolidation of customer service centers and the redesigning various other processes.
The Kentucky Commission responded to the motions filed by KU for computational and other errors made in Orders received on base rate reductions in February 2000 by reducing KU's annual revenue reductions by $2.5 million and granting rehearings on other issues.
Kentucky Utilities Company REPORT OF MANAGEMENT
The management of Kentucky Utilities Company is responsible for the preparation and integrity of the financial statements and related information included in this Annual Report. These statements have been prepared in accordance with generally accepted accounting principles applied on a consistent basis and, necessarily, include amounts that reflect the best estimates and judgment of management.
KU's financial statements have been audited by Arthur Andersen LLP, independent public accountants. Management has made available to Arthur Andersen LLP all KU's financial records and related data as well as the minutes of shareholders' and directors' meetings.
Management has established and maintains a system of internal controls that provide reasonable assurance that transactions are completed in accordance with management's authorization, that assets are safeguarded and that financial statements are prepared in conformity with generally accepted accounting principles. Management believes that an adequate system of internal controls is maintained through the selection and training of personnel, appropriate division of responsibility, establishment and communication of policies and procedures and by regular reviews of internal accounting controls by KU's internal auditors. Management reviews and modifies its system of internal controls in light of changes in conditions and operations, as well as in response to recommendations from the internal auditors. These recommendations for the year ended December 31, 1998, did not identify any material weaknesses in the design and operation of KU's internal control structure.
The Audit Committee of the Board of Directors is composed entirely of outside directors. In carrying out its oversight role for the financial reporting and internal controls of KU, the Audit Committee meets regularly with KU's independent public accountants, internal auditors and management. The Audit Committee reviews the results of the independent accountants' audit of the financial statements and their audit procedures, and discusses the adequacy of internal accounting controls. The Audit Committee also approves the annual internal auditing program, and reviews the activities and results of the internal auditing function. Both the independent public accountants and the internal auditors have access to the Audit Committee at any time.
Kentucky Utilities Company maintains and internally communicates a written code of business conduct that addresses, among other items, potential conflicts of interest, compliance with laws, including those relating to financial disclosure, and the confidentiality of proprietary information.
Kentucky Utilities Company REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders of Kentucky Utilities Company:
We have audited the accompanying balance sheets and statements of capitalization of Kentucky Utilities Company (a Kentucky and Virginia corporation and a wholly-owned subsidiary of LG&E Energy Corp.) as of December 31, 1999 and 1998, and the related statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1999. These financial statements are the responsibility of KU's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Kentucky Utilities Company as of December 31, 1999 and 1998, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1999, in conformity with accounting principles generally accepted in the United States.
Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule listed under Item 14(a)2 is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audit of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
Louisville, Kentucky Arthur Andersen LLP January 26, 2000 (Except with respect to the matters discussed in Note 14, as to which the date is March 3, 2000.)
ITEM 9.
ITEM 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
PART III
ITEMS 10, 11, 12 and 13 are omitted pursuant to General Instruction G of Form 10-K. The information required by ITEMS 10, 11, 12 and 13 for LG&E Energy and LG&E is incorporated herein by reference to their respective definitive proxy statements to be filed during April 2000 with the Commission pursuant to Regulation 14A of the Securities and Exchange Act of 1934. The information required by ITEMS 10, 11, 12 and 13 for KU is incorporated herein by reference to the material appearing in Exhibit 99.03, which is filed herewith. Additionally, in accordance with General Instruction G, the information required by ITEM 10
ITEM 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.
(a) 1. Financial Statements (included in Item 8):
LG&E Energy: Consolidated statements of income for the three years ended December 31, 1999 (page 75). Consolidated statements of retained earnings for the three years ended December 31, 1999 (page 76). Consolidated statements of comprehensive income for the three years ended December 31, 1999 (page 76) Consolidated balance sheets - December 31, 1999, and 1998 (page 77). Consolidated statements of cash flows for the three years ended December 31, 1999 (page 78). Consolidated statements of capitalization - December 31, 1999, and 1998 (page 79). Notes to consolidated financial statements (pages 81-116). Report of management (page 117). Report of independent public accountants (page 118).
LG&E: Statements of income for the three years ended December 31, 1999 (page 119). Statements of retained earnings for the three years ended December 31, 1999 (page 119). Statements of comprehensive income for the three years ended December 31, 1999 (page 120). Balance sheets - December 31, 1999, and 1998 (page 121). Statements of cash flows for the three years ended December 31, 1999 (page 122). Statements of capitalization - December 31, 1999, and 1998 (page 123). Notes to financial statements (pages 124-142). Report of management (page 143). Report of independent public accountants (page 144).
KU: Statements of income for the three years ended December 31, 1999 (page 145). Statements of retained earnings for the three years ended December 31, 1999 (page 145). Balance sheets - December 31, 1999, and 1998 (page 146). Statements of cash flows for the three years ended December 31, 1999 (page 147). Statements of capitalization - December 31, 1999, and 1998 (page 148). Notes to financial statements (pages 149-164). Report of management (page 165). Report of independent public accountants (page 166).
2. Financial Statement Schedules (included in Part IV):
Schedule II Valuation and Qualifying Accounts for the three years ended December 31, 1999, for LG&E Energy (page 192), LG&E (page 193), and KU (page 194).
All other schedules have been omitted as not applicable or not required or because the information required to be shown is included in the Financial Statements or the accompanying Notes to Financial Statements.
3. Exhibits:
Applicable to Form 10-K of
Exhibit LG&E No. Energy LG&E KU Description - --- ------ ---- -- -----------
2.01 x x x Copy of Agreement and Plan of Merger, dated as of February 27, 2000, by and among PowerGen plc, LG&E Energy Corp., US Subholdco2 and Merger Sub, including certain exhibits thereto. [Filed as Exhibit 1 to LG&E Energy's Current Report on Form 8-K filed February 29, 2000 and incorporated by reference herein]
2.02 x x x Copy of Agreement and Plan of Merger, dated as of May 20, 1997, by and between LG&E Energy and KU Energy, including certain exhibits thereto. [Filed as Exhibit 2 to LG&E Energy's Current Report on Form 8-K filed May 30, 1997 and incorporated by reference herein]
3.01 x Copy of LG&E Energy's Amended and Restated Articles of Incorporation dated May 4, 1998. [Filed as Exhibit 4.1 to LG&E Energy's Current Report on Form 8-K dated May 4, 1998, and incorporated by reference herein]
3.02 x Copy of Restated Articles of Incorporation of LG&E, dated November 6, 1996. [Filed as Exhibit 3.06 to LG&E's Quarterly Report on Form 10-Q for the quarter ended September 30, 1996, and incorporated by reference herein]
3.03 x Copy of Bylaws of LG&E Energy, as amended through June 2, 1999.
Applicable to Form 10-K of
Exhibit LG&E No. Energy LG&E KU Description - --- ------ ---- -- -----------
3.04 x Copy of By-Laws of LG&E, as amended through June 2, 1999.
3.05 x Copy of Amended and Restated Articles of Incorporation of KU [Filed as Exhibits 4.03 and 4.04 to Form 8-K Current Report of KU, dated December 10, 1993, and incorporated by reference herein]
3.06 x Copy of By-laws of KU, as amended through June 2, 1999.
4.01 x x Copy of Trust Indenture dated November 1, 1949, from LG&E to Harris Trust and Savings Bank, Trustee. [Filed as Exhibit 7.01 to LG&E's Registration Statement 2-8283 and incorporated by reference herein]
4.02 x x Copy of Supplemental Indenture dated February 1, 1952, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.05 to LG&E's Registration Statement 2-9371 and incorporated by reference herein]
4.03 x x Copy of Supplemental Indenture dated February 1, 1954, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.03 to LG&E's Registration Statement 2-11923 and incorporated by reference herein]
4.04 x x Copy of Supplemental Indenture dated September 1, 1957, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.04 to LG&E's Registration Statement 2-17047 and incorporated by reference herein]
4.05 x x Copy of Supplemental Indenture dated October 1, 1960, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.05 to LG&E's Registration Statement 2-24920 and incorporated by reference herein]
4.06 x x Copy of Supplemental Indenture dated June 1, 1966, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.06 to LG&E's Registration Statement 2-28865 and incorporated by reference herein]
4.07 x x Copy of Supplemental Indenture dated June 1, 1968, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.07 to LG&E's Registration Statement 2-37368 and incorporated by reference herein]
4.08 x x Copy of Supplemental Indenture dated June 1, 1970, which is a
Applicable to Form 10-K of
Exhibit LG&E No. Energy LG&E KU Description - --- ------ ---- -- -----------
supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.08 to LG&E's Registration Statement 2-37368 and incorporated by reference herein]
4.09 x x Copy of Supplemental Indenture dated August 1, 1971, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.09 to LG&E's Registration Statement 2-44295 and incorporated by reference herein]
4.10 x x Copy of Supplemental Indenture dated June 1, 1972, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.10 to LG&E's Registration Statement 2-52643 and incorporated by reference herein]
4.11 x x Copy of Supplemental Indenture dated February 1, 1975, which is a supplemental instrument to exhibit 4.01 hereto. [Filed as Exhibit 2.11 to LG&E's Registration Statement 2-57252 and incorporated by reference herein]
4.12 x x Copy of Supplemental Indenture dated September 1, 1975, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.12 to LG&E's Registration Statement 2-57252 and incorporated by reference herein]
4.13 x x Copy of Supplemental Indenture dated September 1, 1976, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.13 to LG&E's Registration Statement 2-57252 and incorporated by reference herein]
4.14 x x Copy of Supplemental Indenture dated October 1, 1976, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.14 to LG&E's Registration Statement 2-65271 and incorporated by reference herein]
4.15 x x Copy of Supplemental Indenture dated June 1, 1978, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.15 to LG&E's Registration Statement 2-65271 and incorporated by reference herein]
4.16 x x Copy of Supplemental Indenture dated February 15, 1979, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 2.16 to LG&E's Registration Statement 2-65271 and incorporated by reference herein]
4.17 x x Copy of Supplemental Indenture dated September 1, 1979, which
Applicable to Form 10-K of
Exhibit LG&E No. Energy LG&E KU Description - --- ------ ---- -- -----------
is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.17 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1980, and incorporated by reference herein]
4.18 x x Copy of Supplemental Indenture dated September 15, 1979, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.18 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1980, and incorporated by reference herein]
4.19 x x Copy of Supplemental Indenture dated September 15, 1981, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.19 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1981, and incorporated by reference herein]
4.20 x x Copy of Supplemental Indenture dated March 1, 1982, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.20 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1982, and incorporated by reference herein]
4.21 x x Copy of Supplemental Indenture dated March 15, 1982, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.21 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1982, and incorporated by reference herein]
4.22 x x Copy of Supplemental Indenture dated September 15, 1982, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.22 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1982, and incorporated by reference herein]
4.23 x x Copy of Supplemental Indenture dated February 15, 1984, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.23 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1984, and incorporated by reference herein]
4.24 x x Copy of Supplemental Indenture dated July 1, 1985, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.24 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1985, and incorporated by reference herein]
4.25 x x Copy of Supplemental Indenture dated November 15, 1986,
Applicable to Form 10-K of
Exhibit LG&E No. Energy LG&E KU Description - --- ------ ---- -- -----------
which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.25 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1986, and incorporated by reference herein]
4.26 x x Copy of Supplemental Indenture dated November 16, 1986, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.26 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1986, and incorporated by reference herein]
4.27 x x Copy of Supplemental Indenture dated August 1, 1987, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.27 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1987, and incorporated by reference herein]
4.28 x x Copy of Supplemental Indenture dated February 1, 1989, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.28 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1988, and incorporated by reference herein]
4.29 x x Copy of Supplemental Indenture dated February 2, 1989, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.29 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1988, and incorporated by reference herein]
4.30 x x Copy of Supplemental Indenture dated June 15, 1990, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.30 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1990, and incorporated by reference herein]
4.31 x x Copy of Supplemental Indenture dated November 1, 1990, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.31 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1990, and incorporated by reference herein]
4.32 x x Copy of Supplemental Indenture dated September 1, 1992, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.32 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1992, and incorporated by reference herein]
Applicable to Form 10-K of
Exhibit LG&E No. Energy LG&E KU Description - --- ------ ---- -- -----------
4.33 x x Copy of Supplemental Indenture dated September 2, 1992, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.33 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1992, and incorporated by reference herein]
4.34 x x Copy of Supplemental Indenture dated August 15, 1993, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.34 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
4.35 x x Copy of Supplemental Indenture dated August 16, 1993, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.35 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
4.36 x x Copy of Supplemental Indenture dated October 15, 1993, which is a supplemental instrument to Exhibit 4.01 hereto. [Filed as Exhibit 4.36 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
4.37 x x Indenture of Mortgage or Deed of Trust dated May 1, 1947, between KU and First Trust National Association (successor Trustee) and a successor individual co-trustee, as Trustees (the Trustees) (Amended Exhibit 7(a) in File No. 2-7061), and Supplemental Indentures thereto dated, respectively, January 1, 1949 (Second Amended Exhibit 7.02 in File No. 2-7802), July 1, 1950 (Amended Exhibit 7.02 in File No. 2-8499), June 15, 1951 (Exhibit 7.02(a) in File No. 2-8499), June 1, 1952 (Amended Exhibit 4.02 in File No. 2-9658), April 1, 1953 (Amended Exhibit 4.02 in File No. 2-10120), April 1, 1955 (Amended Exhibit 4.02 in File No. 2-11476), April 1, 1956 (Amended Exhibit 2.02 in File No. 2-12322), May 1, 1969 (Amended Exhibit 2.02 in File No. 2-32602), April 1, 1970 (Amended Exhibit 2.02 in File No. 2-36410), September 1, 1971 (Amended Exhibit 2.02 in File No. 2-41467), December 1, 1972 (Amended Exhibit 2.02 in File No. 2-46161), April 1, 1974 (Amended Exhibit 2.02 in File No. 2-50344), September 1, 1974 (Exhibit 2.04 in File No. 2-59328), July 1, 1975 (Exhibit 2.05 in File No. 2-59328), May 15, 1976 (Amended Exhibit 2.02 in File No. 2-56126), April 15, 1977 (Exhibit 2.06 in File No. 2-59328), August 1, 1979 (Exhibit 2.04 in File No. 2-64969), May 1, 1980 (Exhibit 2 to Form 10-Q
Applicable to Form 10-K of
Exhibit LG&E No. Energy LG&E KU Description - --- ------ ---- -- -----------
Quarterly Report of KU for the quarter ended June 30, 1980), September 15, 1982 (Exhibit 4.04 in File No. 2-79891), August 1, 1984 (Exhibit 4B to Form 10-K Annual Report of KU for the year ended December 31, 1984), June 1, 1985 (Exhibit 4 to Form 10-Q Quarterly Report of KU for the quarter ended June 30, 1985), May 1, 1990 (Exhibit 4 to Form 10-Q Quarterly Report of KU for the quarter ended June 30, 1990), May 1, 1991 (Exhibit 4 to Form 10-Q Quarterly Report of KU for the quarter ended June 30, 1991), May 15, 1992 (Exhibit 4.02 to Form 8-K of KU dated May 14, 1992), August 1, 1992 (Exhibit 4 to Form 10-Q Quarterly Report of KU for the quarter ended September 30, 1992), June 15, 1993 (Exhibit 4.02 to Form 8-K of KU dated June 15, 1993) and December 1, 1993 (Exhibit 4.01 to Form 8-K of KU dated December 10, 1993), November 1, 1994 (Exhibit 4.C to Form 10-K Annual Report of KU for the year ended December 31, 1994), June 1, 1995 (Exhibit 4 to Form 10-Q Quarterly Report of KU for the quarter ended June 30, 1995) and January 15, 1996 (Exhibit 4.E to Form 10-K Annual Report of KU for the year ended December 31, 1995). Incorporated by reference.
4.38 x x Supplemental Indenture dated March 1, 1992 between KU and the Trustees, providing for the conveyance of properties formerly held by Old Dominion Power Company [Filed as Exhibit 4B to Form 10-K Annual Report of KU for the year ended December 31, 1992, and incorporated by reference herein]
10.01 x x Copies of Agreement between Sponsoring Companies re: Project D of Atomic Energy Commission, dated May 12, 1952, Memorandums of Understanding between Sponsoring Companies re: Project D of Atomic Energy Commission, dated September 19, 1952 and October 28, 1952, and Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission, dated October 15, 1952. [Filed as Exhibit 13(y) to LG&E's Registration Statement 2-9975 and incorporated by reference herein]
10.02 x x Copy of Modification No. 1 dated July 23, 1953, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 4.03(b) to LG&E's Registration Statement 2-24920 and incorporated by reference herein]
10.03 x x Copy of Modification No. 2 dated March 15, 1964, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 5.02c to LG&E's
Applicable to Form 10-K of
Exhibit LG&E No. Energy LG&E KU Description - --- ------ ---- -- -----------
Registration Statement 2-61607 and incorporated by reference herein]
10.04 x x Copy of Modification No. 3 and No. 4 dated May 12, 1966 and January 7, 1967, respectively, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibits 4(a)(13) and 4(a)(14) to LG&E's Registration Statement 2-26063 and incorporated by reference herein]
10.05 x x Copy of Modification No. 5 dated August 15, 1967, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 13(c) to LG&E's Registration Statement 2-27316 and incorporated by reference herein]
10.06 x x x Copies of (i) Inter-Company Power Agreement, dated July 10, 1953, between Ohio Valley Electric Corporation and Sponsoring Companies (which Agreement includes as Exhibit A the Power Agreement, dated July 10, 1953, between Ohio Valley Electric Corporation and Indiana-Kentucky Electric Corporation); (ii) First Supplementary Transmission Agreement, dated July 10, 1953, between Ohio Valley Electric Corporation and Sponsoring Companies; (iii) Inter-Company Bond Agreement, dated July 10, 1953, between Ohio Valley Electric Corporation and Sponsoring Companies; (iv) Inter-Company Bank Credit Agreement, dated July 10, 1953, between Ohio Valley Electric Corporation and Sponsoring Companies. [Filed as Exhibit 5.02f to LG&E's Registration Statement 2-61607 and incorporated by reference herein]
10.07 x x x Copy of Modification No. 1 and No. 2 dated June 3, 1966 and January 7, 1967, respectively, to Inter-Company Power Agreement dated July 10, 1953. [Filed as Exhibits 4(a)(8) and 4(a)(10) to LG&E's Registration Statement 2-26063 and incorporated by reference herein]
10.08 x x Copies of Amendments to Agreements (iii) and (iv) referred to under 10.06 above as follows: (i) Amendment to Inter-Company Bond Agreement and (ii) Amendment to Inter-Company Bank Credit Agreement. [Filed as Exhibit 5.02h to LG&E's Registration Statement 2-61607 and incorporated by reference herein]
10.09 x x Copy of Modification No. 1, dated August 20, 1958, to First Supplementary Transmission Agreement, dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring
Applicable to Form 10-K of
Exhibit LG&E No. Energy LG&E KU Description - --- ------ ---- -- -----------
Companies. [Filed as Exhibit 5.02i to LG&E's Registration Statement 2-61607 and incorporated by reference herein]
10.10 x x Copy of Modification No. 2, dated April 1, 1965, to the First Supplementary Transmission Agreement, dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 5.02j to LG&E's Registration Statement 2-61607 and incorporated by reference herein]
10.11 x x Copy of Modification No. 3, dated January 20, 1967, to First Supplementary Transmission Agreement, dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 4(a)(7) to LG&E's Registration Statement 2-26063 and incorporated by reference herein]
10.12 x x Copy of Modification No. 6 dated November 15, 1967, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 4(g) to LG&E's Registration Statement 2-28524 and incorporated by reference herein]
10.13 x x x Copy of Modification No. 3 dated November 15, 1967, to the Inter-Company Power Agreement dated July 10, 1953. [Filed as Exhibit 4.02m to LG&E's Registration Statement 2-37368 and incorporated by reference herein]
10.14 x x Copy of Modification No. 7 dated November 5, 1975, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 5.02n to LG&E's Registration Statement 2-56357 and incorporated by reference herein]
10.15 x x x Copy of Modification No. 4 dated November 5, 1975, to the Inter-Company Power Agreement dated July 10, 1953. [Filed as Exhibit 5.02o to LG&E's Registration Statement 2-56357 and incorporated by reference herein]
10.16 x x Copy of Modification No. 4 dated April 30, 1976, to First Supplementary Transmission Agreement, dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 5.02p to LG&E's Registration Statement 2-61607 and incorporated by reference herein]
10.17 x x Copy of Modification No. 8 dated June 23, 1977, to the Power Agreement between Ohio Valley Electric Corporation and
Applicable to Form 10-K of
Exhibit LG&E No. Energy LG&E KU Description - --- ------ ---- -- -----------
Atomic Energy Commission. [Filed as Exhibit 5.02q to LG&E's Registration Statement 2-61607 and incorporated by reference herein]
10.18 x x Copy of Modification No. 9 dated July 1, 1978, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 5.02r to LG&E's Registration Statement 2-63149 and incorporated by reference herein]
10.19 x x Copy of Modification No. 10 dated August 1, 1979, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 2 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1979, and incorporated by reference herein]
10.20 x x Copy of Modification No. 11 dated September 1, 1979, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 3 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1979, and incorporated by reference herein]
10.21 x x x Copy of Modification No. 5 dated September 1, 1979, to Inter-Company Power Agreement dated July 5, 1953, among Ohio Valley Electric Corporation and Sponsoring Companies. [Filed as Exhibit 4 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1979, and incorporated by reference herein]
10.22 x x Copy of Modification No. 12 dated August 1, 1981, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 10.25 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1981, and incorporated by reference herein]
10.23 x x x Copy of Modification No. 6 dated August 1, 1981, to Inter-Company Power Agreement dated July 5, 1953, among Ohio Valley Electric Corporation and Sponsoring Companies. [Filed as Exhibit 10.26 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1981, and incorporated by reference herein]
10.24 x x * Copy of LG&E Energy Corp. Deferred Stock Compensation Plan effective January 1, 1992, covering non-employee directors of the Company and its subsidiaries. [Filed as Exhibit 10.34 to
Applicable to Form 10-K of
Exhibit LG&E No. Energy LG&E KU Description - --- ------ ---- -- -----------
the Company's Annual Report on Form 10-K for the year ended December 31, 1991, and incorporated by reference herein]
10.25 x x * Copy of Supplemental Executive Retirement Plan for R. W. Hale, effective June 1, 1989. [Filed as Exhibit 10.42 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992, and incorporated by reference herein]
10.26 x x * Copy of Nonqualified Savings Plan covering officers of the Company, effective January 1, 1992. [Filed as Exhibit 10.43 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992, and incorporated by reference herein]
10.27 x x Copy of Modification No. 13 dated September 1, 1989, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 10.42 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
10.28 x x Copy of Modification No. 14 dated January 15, 1992, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 10.43 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
10.29 x x x Copy of Modification No. 7 dated January 15, 1992, to Inter-Company Power Agreement dated July 10, 1953, among Ohio Valley Electric Corporation and Sponsoring Companies. [Filed as Exhibit 10.44 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
10.30 x x Copy of Modification No. 15 dated February 15, 1993, to the Power Agreement between Ohio Valley Electric Corporation and Atomic Energy Commission. [Filed as Exhibit 10.45 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
10.31 x x Copy of Firm No Notice Transportation Agreement effective November 1, 1993, between Texas Gas Transmission Corporation and LG&E (expires October 31, 2001) covering the transmission of natural gas.
Copy of Firm No Notice Transportation Agreement effective November 1, 1993, between Texas Gas Transmission Corpora-
Applicable to Form 10-K of
Exhibit LG&E No. Energy LG&E KU Description - --- ------ ---- -- -----------
tion and LG&E (expires October 31, 2000) covering the transmission of natural gas.
Copy of Firm No Notice Transportation Agreement effective November 1, 1993, between Texas Gas Transmission Corporation and LG&E (expires October 31, 2003) covering the transmission of natural gas.
[Filed as Exhibit 10.47 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
10.32 x x x * Copy of LG&E Energy Corp. Stock Option Plan for Non-Employee Directors. [Filed as Exhibit 10.51 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993, and incorporated by reference herein]
10.33 x x x Copy of Modification No. 8 dated January 19, 1994, to Intercompany Power Agreement, dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 10.43 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
10.34 x x Copy of Amendment dated March 1 1995, to Firm No-Notice Transportation Agreements dated November 1, 1993 (2-Year, 5-Year and 8-Year), between Texas Gas Transmission Corporation and LG&E covering the transmission of natural gas. [Filed as Exhibit 10.44 of LG&E's Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
10.35 x x x Copy of Modification No. 9, dated August 17, 1995, to the Inter-Company Power Agreement dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies. [Filed as Exhibit 10.39 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1996, and incorporated by reference herein]
10.36 x x Copy of Agreement and Plan of Merger, dated February 10, 1995, between LG&E Natural Inc., formerly known as Hadson Corporation, Carousel Acquisition Corporation and the Company. [Filed as Exhibit 2 of Schedule 13D by the Company on February 21, 1995, and incorporated by reference herein]
Applicable to Form 10-K of
Exhibit LG&E No. Energy LG&E KU Description - --- ------ ---- -- -----------
10.37 x x Copy of Firm Transportation Agreement, dated March 1, 1995, between Texas Gas Transmission Corporation and LG&E (expires October 31, 2003) covering the transportation of natural gas.
Copy of Firm Transportation Agreement, dated March 1, 1995, between Texas Gas Transmission Corporation and LG&E (expires October 31, 2001) covering the transportation of natural gas. [Filed as Exhibit 10.45 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
10.38 x x Copy of Firm Transportation Agreement, dated March 1, 1995, between Texas Gas Transmission Corporation and LG&E (expires October 31, 2000) covering the transportation of natural gas [Filed as Exhibit 10.41 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1996, and incorporated by reference herein]
10.39 x x x * Copy of Amended and Restated Omnibus Long-Term Incentive Plan effective January 1, 1996, covering officers and key employees of the Company. [Filed as Exhibit 10.52 to the Company's Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
10.40 x x x * Copy of Short-Term Incentive Plan effective January 1, 1996, covering officers and key employees of the Company. [Filed as Exhibit 10.53 to the Company's Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
10.41 x x * Copy of Amendment to the Non-Qualified Savings Plan, effective January 1, 1992. [Filed as Exhibit 10.55 to the Company's Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
10.42 x x * Copy of Amendment to the Non-Qualified Savings Plan, effective January 1, 1995. [Filed as Exhibit 10.56 to the Company's Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
10.43 x x * Copy of Amendment to the Non-Qualified Savings Plan, effective January 1, 1995. [Filed as Exhibit 10.57 to the Company's Annual Report on Form 10-K for the year ended December 31, 1995, and incorporated by reference herein]
Applicable to Form 10-K of
Exhibit LG&E No. Energy LG&E KU Description - --- ------ ---- -- -----------
10.44 x x Copy of Form of Master Gas Purchase Agreement, dated December 14, 1993, among Santa Fe, SFEOP and AGPC. [Filed as Exhibit 10.23 to LG&E Natural Inc.'s, formerly known as Hadson Corporation, Registration Statement on Form S-4, File No. 33-68224, and incorporated by reference herein]
10.45 x x Copy of Credit Agreement, dated as of December 18, 1995, among LG&E, as Borrower, the Banks named therein, PNC Bank, Kentucky, Inc. as Agent and Bank of Montreal as Co-Agent. [Filed as Exhibit 10.01 to the LG&E's Quarterly Report on Form 10-Q/A for the quarter ended March 31, 1996, and incorporated by reference herein]
10.46 x x Copy of Firm Transportation Agreement, dated November 1, 1996, between LG&E and Tennessee Gas Pipeline Company for 30,000 Mmbtu per day in Firm Transportation Service under Tennessee's Rate FT-A (expires October 31, 2001). [Filed as Exhibit 10.42 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1996, and incorporated by reference herein]
10.47 x x Copy of Amendment No. 1, dated as of November 5, 1996, to Credit Agreement dated as of December 18, 1995, by and among Louisville Gas and Electric Company, the Banks party thereto, and PNC Bank, Kentucky, Inc. as Agent and Bank of Montreal as Co-Agent. [Filed as Exhibit 10.59 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1996, and incorporated by reference herein]
10.48 x x Copy of Power Purchase and Sale Agreement, dated as of November 19, 1996, among the Company, LG&E Power Marketing Inc., and Oglethorpe Power Corporation. [Filed as Exhibit 10.66 to LG&E Energy's Annual Report on Form 10-K for the year ended December 31, 1996, and incorporated by reference herein] [Certain portions of this exhibit have been omitted pursuant to a confidential treatment request filed with the Securities and Exchange Commission]
10.49 x x Copy of Power Purchase and Sale Agreement, dated as of January 1, 1997, among LG&E Power Marketing Inc., LG&E Power Inc., and Oglethorpe Power Corporation. [Filed as Exhibit 10.67 to LG&E Energy's Annual Report on Form 10-K for the year ended December 31, 1996, and incorporated by reference herein] [Certain portions of this exhibit have been omitted pursuant to a confidential treatment request filed with the Secu-
Applicable to Form 10-K of
Exhibit LG&E No. Energy LG&E KU Description - --- ------ ---- -- -----------
rities and Exchange Commission]
10.50 x Copy of U.S. $500,000,000 Credit Agreement, dated as of September 5, 1997, among LG&E Capital Corp., as Borrower, and the Banks named therein, as Lenders, and Chase Securities Inc., as Syndication Agent, Bank of Montreal, as Administrative Agent, and Morgan Guaranty Trust Company of New York, PNC Bank, Kentucky, Inc., The Bank of New York, The First National Bank of Chicago and Wachovia Bank, N.A., as Co-Agents. [Filed as Exhibit 10.01 to LG&E Energy's Quarterly Report on Form 10-Q for the quarter ended September 30, 1997, and incorporated by reference herein]
10.51 x Copy of U.S. $ 200,000,000 Credit Agreement, dated as of September 5, 1997, among LG&E Capital Corp., as Borrower, and the Banks named therein, as Lenders, and Chase Securities Inc., as Syndication Agent, Bank of Montreal, as Administrative Agent, and Morgan Guaranty Trust Company of New York, PNC Bank, Kentucky, Inc., The Bank of New York, The First National Bank of Chicago and Wachovia Bank, N.A., as Co-Agents. [Filed as Exhibit 10.02 to LG&E Energy's Quarterly Report on Form 10-Q for the quarter ended September 30, 1997, and incorporated by reference herein]
10.52 x Copy of Support Agreement, dated as of September 5, 1997, between LG&E Energy Corp. and LG&E Capital Corp. [Filed as Exhibit 10.03 to LG&E Energy's Quarterly Report on Form 10-Q for the quarter ended September 30, 1997, and incorporated by reference herein]
10.53 x KU Energy Stock Option Agreement, dated as of May 20, 1997, by and between KU Energy and LG&E Energy. [Filed as Exhibit 99.1 to the Company's Current Report on Form 8-K filed May 30, 1997 and incorporated by reference herein]
10.54 x Copy of LG&E Energy Stock Option Agreement, dated as of May 20, 1997, by and between KU Energy and LG&E Energy. [Filed as Exhibit 99.2 to the Company's Current Report on Form 8-K filed May 30, 1997 and incorporated by reference herein]
10.55 x x x * Copy of Employment Agreement between LG&E Energy and Roger W. Hale dated May 20, 1997, effective May 4, 1998. [Filed as Annex D to Exhibit 2.01 of LG&E Energy's Annual Report on Form 10-K for the year ended December 31, 1997, and incorporated by reference herein]
Applicable to Form 10-K of
Exhibit LG&E No. Energy LG&E KU Description - --- ------ ---- -- -----------
10.56 x x * Copy of LG&E Energy Corp. and Louisville Gas and Electric Company Non-Officer Senior Management Pension Restoration Plan, effective May 1, 1996. [Filed as Exhibit 10.69 to LG&E Energy's Annual Report on Form 10-K for the year ended December 31, 1996, and incorporated by reference herein]
10.57 x Copy of Indenture between LG&E Capital Corp. and the Bank of New York as Trustee dated as of January 15, 1998. [Filed as Exhibit 10.72 to LG&E Energy's Annual Report on Form 10-K for the year ended December 31, 1997, and incorporated by reference herein]
10.58 x Copy of First Supplemental Indenture between LG&E Capital Corp. and The Bank of New York as Trustee dated as of January 15, 1998. [Filed as Exhibit 10.73 to LG&E Energy's Annual Report on Form 10-K for the year ended December 31, 1997, and incorporated by reference herein]
10.59 x x x * Copy of Supplemental Executive Retirement Plan as amended through January 1, 1998, covering officers of LG&E Energy. [Filed as Exhibit 10.74 to LG&E Energy's Annual Report on Form 10-K for the year ended December 31, 1997, and incorporated by reference herein]
10.60 x x x * Copy of form of Change in Control Agreement for officers of LG&E Energy Corp. [Filed as Exhibit 10.75 to LG&E Energy's Annual Report on Form 10-K for the year ended December 31, 1997, and incorporated by reference herein]
10.61 x x Copy of Coal Supply Agreement between LG&E and Kindill Mining, Inc., dated July 1, 1997. [Filed as Exhibit 10.76 to LG&E Energy's Annual Report on Form 10-K for the year ended December 31, 1997, and incorporated by reference herein]
10.62 x x Copy of Coal Supply Agreement between LG&E and Warrior Coal Corp. dated January 1, 1997, and Amendments #1 and #2 dated May 1, 1997, and December 1, 1997, thereto. [Filed as Exhibit 10.79 to LG&E Energy's Annual Report on Form 10-K for the year ended December 31, 1997, and incorporated by reference herein]
10.63 x x Copies of Amendments dated September 23, 1997, to Firm No-Notice Transportation Agreements dated November 1, 1993, between Texas Gas Transmission Corporation and LG&E, as amended. [Filed as Exhibit 10.81 to LG&E Energy's Annual
Applicable to Form 10-K of
Exhibit LG&E No. Energy LG&E KU Description - --- ------ ---- -- -----------
Report on Form 10-K for the year ended December 31, 1997, and incorporated by reference herein]
10.64 x x Copies of Amendments dated September 23, 1997, to Firm Transportation Agreements dated March 1, 1995, between Texas Gas Transmission Corporation and LG&E, as amended. [Filed as Exhibit 10.82 to LG&E Energy's Annual Report on Form 10-K for the year ended December 31, 1997, and incorporated by reference herein]
10.65 x x Copy of Gas Transportation Agreement dated November 1, 1996, between Tennessee Gas Pipeline Company and LG&E and amendments dated February 4, 1997, thereto. [Filed as Exhibit 10.83 to LG&E Energy's Annual Report on Form 10-K for the year ended December 31, 1997, and incorporated by reference herein] [Certain portions of this exhibit have been omitted pursuant to a confidential treatment request filed with the Securities and Exchange Commission]
10.66 [Not used.]
10.67 [Not used.]
10.68 [Not used.]
10.69 [Not used.]
10.70 [Not used.]
10.71 [Not used.]
Applicable to Form 10-K of
Exhibit LG&E No. Energy LG&E KU Description - --- ------ ---- -- -----------
10.72 [Not used.]
10.73 [Not used.]
10.74 x x * KU Energy's Long-Term Incentive Plan [Filed as Exhibit 10.27 to Form 10-K Annual Report of KU Energy for the year ended December 31, 1996, and incorporated by reference herein]
10.75 x * Employment Agreement by and between KU Energy Corporation and Michael R. Whitley [Filed as Exhibit (2)-5 to S-4 Registration Statement File No. 333-34219; Annex E to Form DEFM14A Joint Proxy Statement of LG&E Energy Corp. and KU Energy Corporation dated August 22, 1997, and incorporated by reference herein]
10.76 x x Copy of Amended and Restated Coal Supply Agreement dated April 1, 1998 between LG&E and Hopkins County Coal LLC. [Filed as Exhibit 10.76 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1998 and incorporated by reference herein]
10.77 x x Copy of Coal Supply Agreement dated January 1, 1999 between LG&E and Peabody COALSALES Company. [Filed as Exhibit 10.77 to LG&E's Annual Report on Form 10-K for the year ended December 31, 1998 and incorporated by reference herein]
10.78 [Not used.]
10.79 [Not used.]
Applicable to Form 10-K of
Exhibit LG&E No. Energy LG&E KU Description - --- ------ ---- -- -----------
10.80 x x Copy of Assignment and Assumption Agreement dated November 16, 1998 between KU, Leslie Resources, Inc. and AEI Coal Sales Company, Inc. regarding Coal Supply Agreement dated December 31, 1997. [Filed as Exhibit 10.80 to KU's Annual Report on Form 10-K for the year ended December 31, 1998 and incorporated by reference herein]
10.81 x x Copy of Coal Supply Agreement dated April 1, 1995 between KU and Consolidation Coal Company, Quarto Mining Company, McElroy Coal Company, Consol Pennsylvania Coal Company, Greenon Coal Company and Nineveh Coal Company. [Filed as Exhibit 10.81 to KU's Annual Report on Form 10-K for the year ended December 31, 1998 and incorporated by reference herein]
10.82 x x Copy of Amendment to Coal Supply Agreement dated October 1, 1996 between KU and Consolidation Coal Company, Quarto Mining Company, McElroy Coal Company, Consol Pennsylvania Coal Company, Greenon Coal Company and Nineveh Coal Company regarding Coal Supply Agreement dated April 1, 1995. [Filed as Exhibit 10.82 to KU's Annual Report on Form 10-K for the year ended December 31, 1998 and incorporated by reference herein]
10.83 x Copy of New Participation Agreement dated April 6, 1998, among Big Rivers Electric Corporation. LG&E Energy Marketing Inc., Western Kentucky Leasing Corp., WKE Station Two Inc. and Western Kentucky Energy Corp. [Certain portions of this exhibit have been omitted pursuant to a confidential treatment request filed with the Securities and Exchange Commission.] [Filed as Exhibit 10.83 to LG&E Energy's Annual Report on Form 10-K for the year ended December 31, 1998 and incorporated by reference herein]
10.84 x Copy of Letter Agreement from WKE Station Two Inc. to Big Rivers Electric Corporation dated April 6, 1998 amending New Participation Agreement dated April 6, 1998 among Big Rivers Electric Corporation. LG&E Energy Marketing Inc., Western Kentucky Leasing Corp., WKE Station Two Inc. and Western Kentucky Energy Corp. [Certain portions of this exhibit have been omitted pursuant to a confidential treatment request filed with the Securities and Exchange Commission.] [Filed as Exhibit 10.84 to LG&E Energy's Annual Report on Form 10-K for the year ended December 31, 1998 and incorporated by reference herein]
Applicable to Form 10-K of
Exhibit LG&E No. Energy LG&E KU Description - --- ------ ---- -- -----------
10.85 x Copy of Second Amendment dated June 15, 1998 to New Participation Agreement dated April 6, 1998 among Big Rivers Electric Corporation. LG&E Energy Marketing Inc., Western Kentucky Leasing Corp., WKE Station Two Inc. and Western Kentucky Energy Corp. [Certain portions of this exhibit have been omitted pursuant to a confidential treatment request filed with the Securities and Exchange Commission.] [Filed as Exhibit 10.85 to LG&E Energy's Annual Report on Form 10-K for the year ended December 31, 1998 and incorporated by reference herein]
10.86 x Copy of Third Amendment dated July 15, 1998 to New Participation Agreement dated April 6, 1998 among Big Rivers Electric Corporation. LG&E Energy Marketing Inc., Western Kentucky Leasing Corp., WKE Station Two Inc. and Western Kentucky Energy Corp. [Certain portions of this exhibit have been omitted pursuant to a confidential treatment request filed with the Securities and Exchange Commission.] [Filed as Exhibit 10.86 to LG&E Energy's Annual Report on Form 10-K for the year ended December 31, 1998 and incorporated by reference herein]
10.87 x Copy of Form of Lease and Operating Agreement Between Western Kentucky Energy Corp. and Big Rivers Electric Corporation dated July 15, 1998. [Certain portions of this exhibit have been omitted pursuant to a confidential treatment request filed with the Securities and Exchange Commission.] [Filed as Exhibit 10.87 to LG&E Energy's Annual Report on Form 10-K for the year ended December 31, 1998 and incorporated by reference herein]
10.88 x Copy of Power Purchase Agreement Between Big Rivers Electric Corporation and LG&E Energy Marketing Inc. dated July 15, 1998. [Certain portions of this exhibit have been omitted pursuant to a confidential treatment request filed with the Securities and Exchange Commission.] [Filed as Exhibit 10.88 to LG&E Energy's Annual Report on Form 10-K for the year ended December 31, 1998 and incorporated by reference herein]
10.89 x Copy of Agreement and Amendments to Agreements By and Among City of Henderson, Kentucky, City of Henderson Utility
Applicable to Form 10-K of
Exhibit LG&E No. Energy LG&E KU Description - --- ------ ---- -- -----------
Commission, Big Rivers Electric Corporation, WKE Station Two Inc., LG&E Energy Marketing Inc., and Western Kentucky Energy Corp. dated July 15, 1998. [Filed as Exhibit 10.89 to LG&E Energy's Annual Report on Form 10-K for the year ended December 31, 1998 and incorporated by reference herein]
10.90 x x x * Copy of Amendment to LG&E Energy's Supplemental Executive Retirement Plan, effective September 2, 1998. [Filed as Exhibit 10.90 to LG&E Energy's Annual Report on Form 10-K for the year ended December 31, 1998 and incorporated by reference herein]
10.91 x x x * Copy of Amendment effective September 2, 1998 to Supplemental Executive Retirement Plan for R. W. Hale effective June 1, 1989. [Filed as Exhibit 10.91 to LG&E Energy's Annual Report on Form 10-K for the year ended December 31, 1998 and incorporated by reference herein]
10.92 x Copy of Terms Agreement among LG&E Capital Corp., LG&E Energy Corp., Morgan Stanley & Co. Incorporated, Chase Securities Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated and J.P. Morgan Securities Inc. dated October 29, 1998. [Filed as Exhibit 10.92 to LG&E Energy's Annual Report on Form 10-K for the year ended December 31, 1998 and incorporated by reference herein]
10.93 x x x * Copy of Employment Agreement, dated as of February 25, 2000, by and among LG&E Energy, PowerGen plc and Roger W. Hale. [Filed as Exhibit 1 to Appendix A of LG&E Energy's Preliminary Proxy Statement on Schedule 14A on March 13, 2000 and incorporated by reference herein]
10.94 x x x * Copy of form of Employment and Severance Agreement, dated as of February 25, 2000, by and among LG&E Energy, PowerGen plc and certain executive officers of the Company.
10.95 x x x * Copy of Amendment dated as of April 21, 1999, to Amended and Restated Omnibus Long-Term Incentive Plan, covering officers and key employees of LG&E Energy.
10.96 x x x * Copy of Amendment, effective October 1, 1999, to LG&E Energy's Non-Qualified Savings Plan.
10.97 x x x * Copy of Amendment, effective December 1, 1999, to LG&E
Applicable to Form 10-K of
Exhibit LG&E No. Energy LG&E KU Description - --- ------ ---- -- -----------
Energy's Non-Qualified Savings Plan.
10.98 [Not used.]
10.99 x Copy of Agency Agreement, dated September 1, 1999, between LG&E Capital Corp. and Wachovia Securities Inc.
10.100 x Copy of Terms Agreement, dated May 4, 1999, among LG&E Capital Corp., J.P. Morgan Securities Inc., Chase Securities Inc. and Merrill Lynch & Co.
10.101 x Copy of Second Supplemental Indenture, dated as of September 1, 1999 between LG&E Capital Corp. and The Bank of New York as Trustee.
10.102 x x x Copy of Modification No. 10., dated January 1, 1998, to the Inter-Company Power Agreement dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies.
10.103 x x x Copy of Modification No. 11, dated April 1, 1999, to the Inter-Company Power Agreement dated July 10, 1953, among Ohio Valley Electric Corporation and the Sponsoring Companies.
10.104 x x Copy of Amendment No. 1, dated January 1, 2000, to Amended and Restated Coal Supply Agreement, dated April 1, 1998, among LG&E, Hopkins County Coal, LLC and Webster County Coal, LLC.
10.105 x x Copy of Amendment No. 1, dated January 1, 2000, to Coal Supply Contract, dated January 1, 1999, between LG&E and Peabody CoalSales Company.
10.106 x x Copy of Letter Amendment, dated September 15, 1999, to Transportation Agreement, dated November 1, 1993, between LG&E and Texas Gas Transmission Corporation.
12 x x Computation of Ratio of Earnings to Fixed Charges for LG&E and KU.
21 x x x Subsidiaries of the Registrant.
23.01 x Consent of Independent Public Accountants for LG&E Energy Corp.
23.02 x Consent of Independent Public Accountants for LG&E.
23.03 x Consent of Independent Public Accountants for KU.
24 x x x Power of Attorney.
27 x x x Financial Data Schedules for LG&E Energy Corp., LG&E and KU.
99.01 x x x Cautionary Statement for purposes of the "Safe Harbor" provisions of the Private Securities Litigation Reform Act of 1995.
99.02 x Description of Common Stock.
99.03 x Director and Officer Information.
(b) Executive Compensation Plans and Arrangements:
Exhibits preceded by an asterisk ("*") above are management contracts, compensation plans or arrangements required to be filed as an exhibit pursuant to Item 14(c) of Form 10-K.
(c) Reports on Form 8-K:
On December 21, 1999, the Company filed a report on Form 8-K announcing that LG&E Energy, LG&E and KU realigned their management structures to support their efforts to prepare for the changing energy marketplace.
On January 6, 2000, the Company filed a report on Form 8-K announcing that on December 21, 1999, it received an adverse order from the arbitration panel considering its contract dispute with OPC.
On January 25, 2000, the Company filed a report on Form 8-K announcing that on January 7, 2000, it issued a statement regarding the Kentucky Commission's decision in the PBR case involving its two utility subsidiaries, LG&E and KU.
On February 29, 2000, the Company filed a report on Form 8-K announcing that on February 27, 2000, it and PowerGen entered into an Agreement and Plan of Merger.
(d) The following instruments defining the rights of holders of certain long- term debt of KU have not been filed with the Securities and Exchange Commission but will be furnished to the Commission upon request.
1. Loan Agreement dated as of May 1, 1990 between KU and the County of Mercer, Kentucky, in connection with $12,900,000 County of Mercer, Kentucky, Collateralized Solid Waste Disposal Facility Revenue Bonds (KU Project) 1990 Series A, due May 1, 2010 and May 1, 2020.
2. Loan Agreement dated as of May 1, 1991 between KU and the County of Carroll, Kentucky, in connection with $96,000,000 County of Carroll, Kentucky, Collateralized Pollution Control Revenue Bonds (KU Project) 1992 Series A, due September 15, 2016.
3. Loan Agreement dated as of August 1, 1992 between KU and the County of Carroll, Kentucky, in connection with $2,400,000 County of Carroll, Kentucky, Collateralized Pollution Control Revenue Bonds (KU Project) 1992 Series C, due February 1, 2018.
4. Loan Agreement dated as of August 1, 1992 between KU and the County of Muhlenberg, Kentucky, in connection with $7,200,000 County of Muhlenberg, Kentucky, Collateralized Pollution Control Revenue Bonds (KU Project) 1992 Series A, due February 1, 2018.
5. Loan Agreement dated as of August 1, 1992 between KU and the County of Mercer, Kentucky, in connection with $7,400,000 County of Mercer, Kentucky, Collateralized Pollution Control Revenue Bonds (KU Project) 1992 Series A, due February 1, 2018.
6. Loan Agreement dated as of August 1, 1992 between KU and the County of Carroll, Kentucky, in connection with $20,930,000 County of Carroll, Kentucky, Collateralized Pollution Control Revenue Bonds (KU Project) 1992 Series B, due February 1, 2018.
7. Loan Agreement dated as of December 1, 1993, between KU and the County of Carroll, Kentucky, in connection with $50,000,000 County of Carroll, Kentucky, Collateralized Solid Waste Disposal Facilities Revenue Bonds (KU Project) 1993 Series A, due December 1, 2023.
8. Loan Agreement dated as of November 1, 1994, between KU and the County of Carroll, Kentucky, in connection with $54,000,000 County of Carroll, Kentucky, Collateralized Solid Waste Disposal Facilities Revenue Bonds (KU Project) 1994 Series A, due November 1, 2024.
Schedule II
LG&E Energy Corp. and Subsidiaries Schedule II - Valuation and Qualifying Accounts For the Three Years Ended December 31, 1999 (Thousands of $)
(a) Amounts presented are after tax. (b) Partially offsets a deferred tax debit included in net assets of discontinued operations. The debit represents net operating loss carryforwards available from a previous acquisition.
Schedule II
Louisville Gas and Electric Company Schedule II - Valuation and Qualifying Accounts For the Three Years Ended December 31, 1999 (Thousands of $)
Other Accounts Property Receivable and (Uncollectible Investments Accounts) ----------- ---------
Balance December 31, 1996 $63 $1,470
Additions: Charged to costs and expenses -- 2,300 Deductions: Net charges of nature for which reserves were created -- 2,475 --- ------
Balance December 31, 1997 63 1,295
Additions: Charged to costs and expenses -- 2,300 Deductions: Net charges of nature for which reserves were created -- 2,196 --- ------
Balance December 31, 1998 63 1,399
Additions: Charged to costs and expenses -- 1,925 Deductions: Net charges of nature for which reserves were created -- 2,091 --- ------
Balance December 31, 1999 $63 $1,233 === ======
Schedule II
Kentucky Utilities Company Schedule II - Valuation and Qualifying Accounts For the Three Years Ended December 31, 1999 (Thousands of $)
Other Accounts Property Receivable and (Uncollectible Investments Accounts) ----------- ---------
Balance December 31, 1996 $263 $ 520
Additions: Charged to costs and expenses 82 1,374 Deductions: Net charges of nature for which reserves were created -- 1,374 ---- ------
Balance December 31, 1997 345 520
Additions: Charged to costs and expenses 231 1,308 Deductions: Net charges of nature for which reserves were created -- 1,308 ---- ------
Balance December 31, 1998 576 520
Additions: Charged to costs and expenses 111 1,707 Deductions: Net charges of nature for which reserves were created -- 1,427 ---- ------
Balance December 31, 1999 $687 $ 800 ==== ======
SIGNATURES - LG&E ENERGY CORP. (First of Two Pages)
Pursuant to the requirements of Section 13 or 15(d) 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.
LG&E ENERGY CORP. Registrant
March 24, 2000 /s/ R. Foster Duncan - -------------- -------------------- (Date) R. Foster Duncan Executive Vice President and Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
Signature Title Date - --------- ----- ----
Roger W. Hale Chairman of the Board, and Chief Executive Officer (Principal Executive Officer);
R. Foster Duncan Executive Vice President and Chief Financial Officer (Principal Financial Officer);
Michael D. Robinson Vice President and Controller (Principal Accounting Officer);
Mira S. Ball Director;
William C. Ballard, Jr. Director;
Owsley Brown, II Director;
Carol M. Gatton Director;
J. David Grissom Director;
David B. Lewis Director;
Anne H. McNamara Director;
By /s/ R. Foster Duncan March 24, 2000 -------------------- R. Foster Duncan (Attorney-In-Fact)
SIGNATURES - LG&E ENERGY CORP. (Second of Two Pages)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
Signature Title Date - --------- ----- ----
T. Ballard Morton, Jr. Director;
Frank V. Ramsey, Jr. Director;
William L. Rouse, Jr. Director;
Charles L. Shearer, Ph.D. Director; and
Lee T. Todd, Jr., Ph.D. Director.
By /s/ R. Foster Duncan March 24, 2000 -------------------- R. Foster Duncan (Attorney-In-Fact)
SIGNATURES - LOUISVILLE GAS AND ELECTRIC COMPANY (First of Two Pages)
Pursuant to the requirements of Section 13 or 15(d) 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.
LOUISVILLE GAS AND ELECTRIC COMPANY Registrant
March 24, 2000 /s/ R. Foster Duncan - -------------- -------------------- (Date) R. Foster Duncan Executive Vice President and Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
Signature Title Date - --------- ----- ----
Roger W. Hale Chairman of the Board, and Chief Executive Officer (Principal Executive Officer);
R. Foster Duncan Executive Vice President and Chief Financial Officer (Principal Financial Officer);
Michael D. Robinson Vice President and Controller (Principal Accounting Officer);
Mira S. Ball Director;
William C. Ballard, Jr. Director;
Owsley Brown, II Director;
Carol M. Gatton Director;
J. David Grissom Director;
David B. Lewis Director;
By /s/ R. Foster Duncan March 24, 2000 -------------------- R. Foster Duncan (Attorney-In-Fact)
SIGNATURES - LOUISVILLE GAS AND ELECTRIC COMPANY (Second of Two Pages)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
Signature Title Date - --------- ----- ----
Anne H. McNamara Director;
T. Ballard Morton, Jr. Director;
Frank V. Ramsey, Jr. Director;
William L. Rouse, Jr. Director;
Charles L. Shearer, Ph.D. Director;
Lee T. Todd, Jr., Ph.D. Director.
By /s/ R. Foster Duncan March 24, 2000 -------------------- R. Foster Duncan (Attorney-In-Fact)
SIGNATURES - KENTUCKY UTILITIES COMPANY (First of Two Pages)
Pursuant to the requirements of Section 13 or 15(d) 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.
KENTUCKY UTILITIES COMPANY Registrant
March 24, 2000 /s/ R. Foster Duncan - -------------- -------------------- (Date) R. Foster Duncan Executive Vice President and Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
Signature Title Date - --------- ----- ----
Roger W. Hale Chairman of the Board, and Chief Executive Officer (Principal Executive Officer);
R. Foster Duncan Executive Vice President and Chief Financial Officer (Principal Financial Officer);
Michael D. Robinson Vice President and Controller (Principal Accounting Officer);
Mira S. Ball Director;
William C. Ballard, Jr. Director;
Owsley Brown, II Director;
Carol M. Gatton Director;
J. David Grissom Director;
David B. Lewis Director;
Anne H. McNamara Director;
By /s/ R. Foster Duncan March 24, 2000 -------------------- R. Foster Duncan (Attorney-In-Fact)
SIGNATURES - KENTUCKY UTILITIES COMPANY (Second of Two Pages)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
Signature Title Date - --------- ----- ----
T. Ballard Morton, Jr. Director;
Frank V. Ramsey, Jr. Director;
William L. Rouse, Jr. Director;
Charles L. Shearer, Ph.D. Director; and
Lee T. Todd, Jr., Ph.D. Director.
By /s/ R. Foster Duncan March 24, 2000 -------------------- R. Foster Duncan (Attorney-In-Fact)