Annual Report — [x] Reg. S-K Item 405 — Form 10-K
Filing Table of Contents
Document/Exhibit Description Pages Size
1: 10-K405 Form 10-K -- Long Island Lighting Company 116 601K
2: EX-4.A Twenty-Seventh Supplemental Indenture 6/1/94 73 282K
3: EX-4.B Fiftieth Supplemental Indenture Dated 6/1/94 37 145K
4: EX-10.W Indenture of Trust Dated October 1, 1994 162 641K
5: EX-10.Y.1 Executive Employment Agreement Dated 1/30/84 14 56K
6: EX-10.Y.2 Form of Executive Employment Agreement 11/21/94 13 52K
7: EX-10.Y.3 Form of Indemnification Agreements 11 43K
8: EX-10.Y.4 Form of Indemnification Agreements 11 43K
9: EX-10.Y.9 Form of Consulting Agreement Dated April 12, 1994 2 10K
10: EX-23 Consent of Ernst & Young LLP, Indepdent Auditors 1 8K
11: EX-24.A Powers of Attorney 12 33K
12: EX-24.B Certificate as to Corporate Power of Attorney 1 8K
13: EX-24.C Certified Copy of Resolution 2 10K
14: EX-27 Financial Data Schedule 2± 10K
| Page | (sequential) | | | | (alphabetic) | Top |
|---|
| | |
- Alternative Formats (Word, et al.)
- Abbreviations
- Air
- Business
- Capital Requirements, Liquidity and Capital Provided
- Certain Relationships and Related Transactions
- Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
- Common Stock
- Company's Securities, The
- Company, The
- Competitive Environment
- Conservation Services
- Directors and Executive Officers of the Company
- Electric Operations
- Electric Rate Plan
- Electric Rates
- Employees
- Energy Sources
- Environment
- Environmental
- Equity Securities
- Executive Compensation
- Executive Officers of the Company
- Exhibits, Financial Statement Schedules, and Reports on Form 8-K
- Financial Statements and Supplementary Data
- First Mortgage, The
- Gas
- Gas Rates
- Gas Supply
- Gas System Requirements
- Gas Transportation
- Gas Transportation and Supply
- General
- G&R Mortgage
- G&R Mortgage, The
- Human Resources
- Independent Power Producers and Cogenerators
- Interconnections
- Land
- Legal Proceedings
- Management's Discussion and Analysis of Financial Condition and Results of Operations
- Market for the Registrant's Common Equity and Related Stockholder Matters
- New York State Takeover Proposal, The
- Notes to Financial Statements
- Nuclear
- Nuclear Waste
- Oil
- Other Activities
- Other Deliveries
- Other Matters
- Other Regulatory Amortization
- PCRBs
- Peak Shaving
- Preference Stock
- Preferred Stock
- Properties
- Rate Moderation Agreement, The
- Recovery of Transition Costs
- Regulation and Accounting Controls
- Revenues
- Security Ownership of Certain Beneficial Owners and Management
- Selected Financial Data
- Shoreham
- Shoreham Decommissioning
- Signatures
- Storage
- Submission of Matters to A Vote of Security Holders
- System Requirements and Reliability
- Table of Contents
- Territory
- The Company
- The Company's Securities
- The First Mortgage
- The G&R Mortgage
- The New York State Takeover Proposal
- The Rate Moderation Agreement
- Unsecured Debt
- Water
- Winter Seasonal Firm Supply
- Winter Seasonal Pipeline Firm Transportation
- Year-Round Firm Supply
- Year-Round Pipeline Firm Transportation
- 1989 Settlement and Electric Rates
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| 1 | 1st Page - Filing Submission
|
| 2 | Table of Contents
|
| 5 | Abbreviations
|
| 6 | Item 1. Business
|
| " | The Company
|
| " | Territory
|
| 7 | Employees
|
| " | Regulation and Accounting Controls
|
| 8 | The New York State Takeover Proposal
|
| " | Electric Operations
|
| " | General
|
| 9 | System Requirements and Reliability
|
| 10 | Energy Sources
|
| " | Oil
|
| " | Gas
|
| " | Nuclear
|
| 11 | Independent Power Producers and Cogenerators
|
| " | Interconnections
|
| " | Conservation Services
|
| " | 1989 Settlement and Electric Rates
|
| 12 | The Rate Moderation Agreement
|
| " | Electric Rates
|
| 13 | Competitive Environment
|
| " | Shoreham Decommissioning
|
| 14 | Gas System Requirements
|
| " | Gas Transportation and Supply
|
| 15 | Gas Transportation
|
| " | Year-Round Pipeline Firm Transportation
|
| " | Winter Seasonal Pipeline Firm Transportation
|
| " | Storage
|
| " | Other Deliveries
|
| " | Gas Supply
|
| " | Year-Round Firm Supply
|
| 16 | Winter Seasonal Firm Supply
|
| " | Peak Shaving
|
| " | Gas Rates
|
| " | Other Activities
|
| " | Recovery of Transition Costs
|
| " | Environment
|
| 17 | Air
|
| 18 | Water
|
| " | Land
|
| 19 | Nuclear Waste
|
| " | The Company's Securities
|
| 20 | The G&R Mortgage
|
| 21 | The First Mortgage
|
| " | Unsecured Debt
|
| 22 | Equity Securities
|
| " | Preferred Stock
|
| " | Preference Stock
|
| " | Common Stock
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| 23 | Executive Officers of the Company
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| 26 | Capital Requirements, Liquidity and Capital Provided
|
| " | Item 2. Properties
|
| " | Item 3. Legal Proceedings
|
| " | Shoreham
|
| 27 | Environmental
|
| " | Human Resources
|
| " | Other Matters
|
| 28 | Item 4. Submission of Matters to A Vote of Security Holders
|
| 29 | Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters
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| 30 | Item 6:. Selected Financial Data
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| 31 | Revenues
|
| 35 | Item 7:. Management's Discussion and Analysis of Financial Condition and Results of Operations
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| 58 | Other Regulatory Amortization
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| 60 | Item 8. Financial Statements and Supplementary Data
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| 67 | Notes to Financial Statements
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| 75 | Electric Rate Plan
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| 82 | G&R Mortgage
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| 83 | PCRBs
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| 97 | Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
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| " | Item 10. Directors and Executive Officers of the Company
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| " | Item 11. Executive Compensation
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| " | Item 12. Security Ownership of Certain Beneficial Owners and Management
|
| " | Item 13. Certain Relationships and Related Transactions
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| " | Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
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| 107 | Signatures
|
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED]
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1994
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
COMMISSION FILE NUMBER 1-3571
----------
LONG ISLAND LIGHTING COMPANY
INCORPORATED PURSUANT TO THE LAWS OF NEW YORK STATE
----------
INTERNAL REVENUE SERVICE - EMPLOYER IDENTIFICATION NUMBER 11-1019782
175 EAST OLD COUNTRY ROAD, HICKSVILLE, NEW YORK 11801
516-755-6650
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) of the act:
Title of each class so registered:
[Enlarge/Download Table]
Common Stock ($5 par)
Preferred Stock ($100 par, cumulative):
Series B, 5.00% Series E, 4.35% Series I, 5 3/4%, Convertible
Series CC, 7.66%
Preferred Stock ($25 par, cumulative):
Series AA, 7.95% Series GG, $1.67 Series QQ, 7.05%
Series NN, $1.95
General and Refunding Bonds:
8 3/4% Series Due 1996 7.85% Series Due 1999 7.90% Series Due 2008
8 3/4% Series Due 1997 8 5/8% Series Due 2004 9 3/4% Series Due 2021
7 5/8% Series Due 1998 8.50% Series Due 2006 9 5/8% Series Due 2024
Debentures:
7.30% Series Due 1999 7.05% Series Due 2003 8.90% Series Due 2019
7.30% Series Due 2000 7.00% Series Due 2004 9.00% Series Due 2022
6.25% Series Due 2001 7.125% Series Due 2005 8.20% Series Due 2023
7.50% Series Due 2007
NAME OF EACH EXCHANGE ON WHICH EACH CLASS IS REGISTERED: The New York
Stock Exchange and the Pacific Stock Exchange are the only exchanges on which
the Common Stock is registered. The New York Stock Exchange is the only
exchange on which each of the other securities listed above is registered.
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: None
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports) and (2) has been subject to such
filing requirements for the past 90 days.
Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in the definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
The aggregate market value of the Common Stock held by non-affiliates
of the Company at March 1, 1995 was $1,899,279,744. The aggregate market value
of Preferred Stock held by non-affiliates of the Company at March 1, 1995,
established by Lehman Brothers based on the average bid and asked price, was
$606,693,813.
COMMON STOCK ($5 PAR) - SHARES OUTSTANDING AT MARCH 1, 1995: 118,704,301
The Company's proxy statement for its Annual Meeting of Shareowners
to be held on May 24, 1995 has been incorporated by reference into Part III of
this Form 10-K to provide information required in Item 10 (Directors and
Executive Officers of the Company) as to Directors, Item 11 (Executive
Compensation), Item 12 (Security ownership of Certain Beneficial Owners and
Management) and Item 13 (Certain Relationships and Related Transactions).
TABLE OF CONTENTS
[Enlarge/Download Table]
ABBREVIATIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iv
PART I
ITEM 1. BUSINESS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
The Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Territory . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Segments of Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Employees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Regulation and Accounting Controls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
The New York State Takeover Proposal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Electric Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
System Requirements and Reliability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Energy Sources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Nuclear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Independent Power Producers and Cogenerators . . . . . . . . . . . . . . . . . . . . . . . 6
Interconnections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Conservation Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
1989 Settlement and Electric Rates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
The Rate Moderation Agreement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Electric Rates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Competitive Environment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Shoreham Decommissioning . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Gas Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Gas System Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Gas Transportation and Supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Gas Transportation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Year-Round Pipeline Firm Transportation . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Winter Seasonal Pipeline Firm Transportation . . . . . . . . . . . . . . . . . . . . . . . 10
Storage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Other Deliveries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Gas Supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Year-Round Firm Supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Winter Seasonal Firm Supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Peak Shaving . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Gas Rates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Other Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Recovery of Transition Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
i
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Environment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Air . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Water . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
Land . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
Nuclear Waste . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
The Company's Securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
The G&R Mortgage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
The First Mortgage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
Unsecured Debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
Equity Securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
Preferred Stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
Preference Stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
Common Stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
Executive Officers of the Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
Capital Requirements, Liquidity and Capital Provided . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
ITEM 2. PROPERTIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
ITEM 3. LEGAL PROCEEDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
Shoreham . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
Environmental . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
Human Resources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
Other Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS . . . . . . . . . . . . . . . . . . 24
ITEM 6. SELECTED FINANCIAL DATA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS . . . . . . . . . . . . 30
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55
Statement of Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56
Balance Sheet . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57
Statement of Retained Earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59
Statement of Capitalization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59
Statement of Cash Flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61
Notes to Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62
Report of Independent Auditors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 91
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE . . . . . . . . . . . . 92
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92
ITEM 11. EXECUTIVE COMPENSATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT . . . . . . . . . . . . . . . . . . . . . . . 92
ii
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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K . . . . . . . . . . . . . . . . . . . . . . 92
List of Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92
List of Financial Statement Schedules. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93
List of Exhibits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93
Reports on Form 8-K. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100
Schedule II. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 101
SIGNATURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 102
iii
ABBREVIATIONS
The following abbreviations are sometimes used in this Annual Report.
[Enlarge/Download Table]
AFC . . . . . . . . . . . . . . . . . . . Allowance For Funds Used During Construction
BFC . . . . . . . . . . . . . . . . . . . Base Financial Component
BVPA . . . . . . . . . . . . . . . . . . Bondable Value of Property Additions
DEC . . . . . . . . . . . . . . . . . . . New York State Department of Environmental Conservation
DOE . . . . . . . . . . . . . . . . . . . United States Department of Energy
DSM . . . . . . . . . . . . . . . . . . . Demand Side Management
Dth . . . . . . . . . . . . . . . . . . . Dekatherms
EFRBs . . . . . . . . . . . . . . . . . . Electric Facilities Revenue Bonds
EPA . . . . . . . . . . . . . . . . . . . United States Environmental Protection Agency
FCA . . . . . . . . . . . . . . . . . . . Fuel Cost Adjustment
FERC . . . . . . . . . . . . . . . . . . Federal Energy Regulatory Commission
First Mortgage . . . . . . . . . . . . . Indenture of Mortgage and Deed of Trust dated as of September 1, 1951
FRA . . . . . . . . . . . . . . . . . . . Financial Resource Asset
G&R Bonds . . . . . . . . . . . . . . . . General and Refunding Bonds
G&R Mortgage . . . . . . . . . . . . . . General and Refunding Indenture dated as of June 1, 1975
GAAP . . . . . . . . . . . . . . . . . . Generally Accepted Accounting Principles
GWh . . . . . . . . . . . . . . . . . . . Gigawatt Hour
kW . . . . . . . . . . . . . . . . . . . Kilowatts
kWh . . . . . . . . . . . . . . . . . . . Kilowatt hour
LIPA . . . . . . . . . . . . . . . . . . Long Island Power Authority
MW . . . . . . . . . . . . . . . . . . . Megawatts
Niagara Mohawk . . . . . . . . . . . . . Niagara Mohawk Power Corporation
Nine Mile Point 2 . . . . . . . . . . . . Nine Mile Point Nuclear Power Station, Unit 2
NRC . . . . . . . . . . . . . . . . . . . Nuclear Regulatory Commission
NYPA . . . . . . . . . . . . . . . . . . New York Power Authority
NYPP . . . . . . . . . . . . . . . . . . New York Power Pool
NYSEG . . . . . . . . . . . . . . . . . . New York State Electric & Gas Corporation
NYSERDA . . . . . . . . . . . . . . . . . New York State Energy Research and Development Authority
PCRBs . . . . . . . . . . . . . . . . . . Pollution Control Revenue Bonds
PILOTS . . . . . . . . . . . . . . . . . Payments in-lieu-of-taxes
PRP . . . . . . . . . . . . . . . . . . . Potentially Responsible Party
PSC . . . . . . . . . . . . . . . . . . . Public Service Commission of the State of New York
RMA . . . . . . . . . . . . . . . . . . . Rate Moderation Agreement
RMC . . . . . . . . . . . . . . . . . . . Rate Moderation Component
Shoreham . . . . . . . . . . . . . . . . Shoreham Nuclear Power Station
iv
A LISTING OF ABBREVIATIONS FREQUENTLY
USED IN THIS REPORT MAY BE FOUND
IMMEDIATELY AFTER THE TABLE OF CONTENTS
PART I
ITEM 1. BUSINESS
THE COMPANY:
Long Island Lighting Company (the "Company") was incorporated
in 1910 under the Transportation Corporations Law of the State of New York and
supplies electric and gas service in Nassau and Suffolk Counties and to the
Rockaway Peninsula in Queens County, all on Long Island, New York. The mailing
address of the Company is 175 East Old Country Road, Hicksville, New York 11801
and its general telephone number is (516) 755-6650.
TERRITORY:
The Company's service territory covers an area of
approximately 1,230 square miles. The population of the service area,
according to the Company's 1994 estimate, is about 2.7 million persons,
including approximately 98,000 persons who reside in Queens County within the
City of New York. The 1994 population estimate reflects a 0.2% increase since
the 1990 census.
Approximately 80% of all workers residing in Nassau and
Suffolk Counties are employed within the two counties. In 1994, total
non-agricultural employment in Nassau and Suffolk Counties increased by
approximately 4,500 employees, an employment increase of 0.4%. The area served
is predominantly residential, but the Company receives approximately one-half
of its electric revenues from commercial and industrial customers. About 89%
of total employment is non-manufacturing.
SEGMENTS OF BUSINESS:
The percentages of total revenues and operating income before
income taxes derived from electric and gas operations for each of the last
three years are shown in the following table:
[Download Table]
Percentage of Percentage of
Total Operating
Revenues Income
----------------- -------------------
Electric Gas Electric Gas
-------- --- -------- ---
1992 84 16 92 8
1993 82 18 89 11
1994 81 19 91 9
For additional information respecting the Company's electric
and gas financial results and operations, see "Management's Discussion and
Analysis of Financial Condition and Results of Operations for the Year Ended
December 31, 1994, " "Selected Financial Data" and Notes 2, 3, and 11 of Notes
to Financial Statements for the Year Ended December 31, 1994.
EMPLOYEES:
At December 31, 1994, the Company had approximately 5,950
full-time employees, of which approximately 2,450 belong to Local 1049 and
approximately 1,400 belong to Local 1381 of the International Brotherhood of
Electrical Workers. The Company's contracts with these unions will expire on
February 13, 1996.
REGULATION AND ACCOUNTING CONTROLS:
The Company is subject to regulation by the Public Service
Commission of the State of New York (the "PSC") with respect to rates, issuance
and sale of securities, adequacy and continuance of service, safety and siting
of certain facilities, accounting, conservation of energy, management
effectiveness and other matters. To ensure that its accounting controls and
procedures are consistently maintained, the Company actively monitors these
controls and procedures. The Audit Committee of the Company's Board of
Directors, as part of its responsibilities, periodically reviews this
monitoring program.
New York law requires that all utilities be periodically
audited to identify those aspects of their operations, if any, which are in
need of improvement. During 1994, the PSC conducted two separate audits of the
Company, one involving Executive Compensation and the other involving
Management and Accounting Controls. The results of these audits are expected to
be issued to the Company in early 1995. The Company plans to implement those
recommendations that will improve its operations.
The Company is also subject, in certain of its activities, to
the jurisdiction of the United States Department of Energy ("DOE") and the
Federal Energy Regulatory Commission ("FERC"). In addition to its accounting
jurisdiction, FERC has jurisdiction over the rates the Company may charge for
the sale of electric energy for resale in interstate commerce, including the
rates the Company charges for electricity sold to municipal electric systems
within the Company's territory, and for the transmission, through the Company's
system, of electric energy to other utilities or to industrial customers. It
is in part in the exercise of this jurisdiction over transmission that FERC is
currently considering certain issues relating to competition in the electric
industry. For additional information relating to these FERC proceedings see
the discussion under the heading "Management's Discussion and Analysis of
Financial Condition and Results of Operations for the Year Ended December 31,
1994." FERC also has
some jurisdiction over a portion of the Company's gas supplies and substantial
jurisdiction over transportation to the Company of its gas supplies.
Operation of Nine Mile Point Nuclear Power Station, Unit 2
("Nine Mile Point 2"), a nuclear facility in which the Company has an 18%
interest, is subject to regulation by the Nuclear Regulatory Commission
("NRC").
THE NEW YORK STATE TAKEOVER PROPOSAL:
At the request of the then Governor of the State of New York,
on October 13, 1994, the chief executives of the New York Power Authority
("NYPA") and the Long Island Power Authority ("LIPA") invited the Company to
enter into negotiations with them regarding a proposal to convert the Company
into a public power utility. Under the proposal, the two state authorities
contemplated a business combination in which holders of the Company's common
stock would receive $21.50 in cash for each outstanding share of the Company's
common stock. NYPA/LIPA indicated that the completion of this transaction
would be subject to, among other things, the availability of tax-exempt
financing sufficient to complete the transaction and the verification by NYPA
and LIPA that the transaction would result in rate reductions in excess of 10%.
The Company's Board of Directors has authorized the Company to enter into
discussions with NYPA and LIPA to explore the proposal in greater detail, but
no such discussions have been held.
The new governor of the State of New York had empaneled a task
force to study the takeover proposal. While the task force did not make its
recommendation public, published reports in local newspapers indicate that the
task force recommended to reject the proposal.
ELECTRIC OPERATIONS:
General
The Company's system energy requirements are supplied from
sources located both on and off Long Island. The Company's generating sources,
with an aggregate summer generating capability of approximately 4,388,000
kilowatts ("kW"), include five steam electric generating stations and a number
of internal combustion and diesel supplemental generating units, all located on
Long Island, the Company's 18% share of Nine Mile Point 2, a nuclear generating
station located in upstate New York, and a 136 megawatt ("MW") facility located
in Holtsville, Long Island, which is owned and operated by NYPA. This facility
was constructed for the benefit and at the request of the Company and commenced
operation in 1994. Additional generating facilities owned by others, such as
independent power producers and cogenerators located on Long Island and
investor-owned and public electric systems located off Long Island, provide the
balance of the Company's energy supplies.
The following table indicates the 1994 summer capacity of the
Company's major generating facilities, internal combustion units and facilities
under its control as reported to the New York Power Pool ("NYPP") in December
1994:
[Download Table]
Description Number of Units MW
----------- --------------- ----
Northport . . . . . . . . . . . . . . . . . . . . . 4 1,512
Port Jefferson . . . . . . . . . . . . . . . . . . 4 471
Glenwood . . . . . . . . . . . . . . . . . . . . . 2 228
E.F. Barrett/Island Park . . . . . . . . . . . . . 2 387
Far Rockaway . . . . . . . . . . . . . . . . . . . 1 113
Internal Combustion Units . . . . . . . . . . . . . 42 1,352
Nine Mile Point 2 (18% Share) . . . . . . . . . . . 1 189
NYPA Holtsville. . . . . . . . . . . . . . . . . . 1 136
-- -----
Total . . . . . . . . . . . . . . . . . . . . 57 4,388
== =====
The maximum demand on the Company's system to date was
3,967,000 kW on July 9, 1993, representing 83% of its total available
capacity of 4,799,000 kW on that day, which included 548,000 kW of firm
capacity purchased from other sources. By agreement with the NYPP, the Company
is required to maintain, on a monthly basis, an installed and contracted firm
power reserve generating capacity equal to at least 18% of its actual peak
load. The Company is currently meeting this NYPP requirement.
System Requirements and Reliability
In 1994, system kilowatt hour ("kWh") energy requirements were
0.4% higher than in 1993. As a result of the implementation of conservation
programs and the availability to customers of energy supplies from cogeneration
sources discussed below under the heading "Independent Power Producers and
Cogenerators," the Company forecasts a 0.9% decrease and 0.4% increase,
relative to 1994, in system energy requirements for the years 1995 and 1996,
respectively. However, for the period 1995-2004, the Company forecasts an
average annual growth rate in system energy requirements of 0.5%. With the
availability of electricity provided by the Company's existing generating
facilities, by its portion of nuclear energy generated at Nine Mile Point 2 and
by power purchased from other electric systems and certain non-Company-owned
facilities located within the Company's service territory, the Company believes
it has adequate generating sources to meet its energy demands beyond the year
2000.
The Company's system electric requirements for the last three
years were provided as follows:
[Download Table]
Percentage of System Requirements
--------------------------------- Purchased
Oil* Gas* Nuclear** Power***
--- --- --------- ----------
1992 37 19 6 38
1993 33 19 7 41
1994 25 23 9 43
_______________
* Generated on the Company's own system. Oil consumption for the Company's
system electric energy
requirements in 1994 was 7.5 million barrels compared to 9.7 million
barrels in 1993. Certain units may be fired with oil or with natural gas
when it is available on an economic or as-required basis. Gas
consumption for the Company's system electric energy requirements in 1994
was 44.3 million dekatherms ("Dth") compared to 36.3 million Dth in 1993.
** Generated at Nine Mile Point 2.
*** Generated at (i) more economical nuclear, coal, oil and hydroelectric
units owned by other electric systems and transmitted to the Company over
its interconnections; (ii) the NYPA Holtsville facility; and (iii)
cogenerators and independent power producers located within the Company's
service territory.
_______________
In 1992 and 1993, cogenerators and independent power producers
provided 9.4% of the Company's system requirements for each of those years. In
1994, cogenerators and independent power producers provided 9.2% of the
Company's system requirements. After the completion of a 40 MW cogeneration
facility at the Stony Brook campus of the State University of New York ("Stony
Brook") currently expected by mid 1995, independent power producers and
cogenerators will provide an estimated 10.4% of the Company's system energy
requirements.
The Company does not expect any new major independent power
producers or cogenerators to be built on Long Island in the foreseeable future.
Among the reasons supporting this conclusion is the Company's belief that the
market for additional large electric projects to provide power to the Company's
remaining commercial and industrial customers is small. Furthermore, under
federal law, the Company is required to buy energy from qualified producers at
the Company's avoided costs. Current long-range avoided cost estimates for the
Company have significantly reduced the economic advantage to entrepreneurs
seeking to compete with the Company and with existing independent power
producers. For additional information respecting competitive issues facing the
Company, see Item 7, "Management's Discussion and Analysis of Financial
Condition and Results of Operations for the Year Ended December 31, 1994."
Energy Sources
Oil: In recent years, the Company has been able to reduce its
oil requirements generally by burning natural gas and by increasing its power
purchases. The availability and cost of oil used by the Company are affected
by factors beyond its control such as the international oil market,
environmental regulations, conservation measures and the availability of
alternative fuels. The Company's fuel oil is supplied principally by five
suppliers.
For information concerning federal and other regulatory
environmental limitations on fuel oil burned by the Company, see "Environment
-- Air." For additional information concerning the recovery of electric fuel
costs, see Note 1 to Notes to Financial Statements for the Year Ended December
31, 1994.
Gas: In addition to burning oil, several of the Company's
generating stations have the capability of burning natural gas. These
dual-fired units enable the Company to burn the most cost efficient fuel and to
reduce its dependency on oil.
Nuclear: The Company holds an 18% interest in Nine Mile Point
2, a 1,047 MW nuclear generating unit near Oswego, New York. The cotenants of
Nine Mile Point 2, in addition to the Company, are Niagara Mohawk Power
Corporation ("Niagara Mohawk"), New York State Electric & Gas Corporation
("NYSEG"), Rochester Gas and Electric Corporation ("RG&E") and Central Hudson
Gas & Electric Corporation.
For additional information on Nine Mile Point 2 and nuclear
plant insurance, see Notes 5 and 10, respectively, of Notes to Financial
Statements for the Year Ended December 31, 1994.
Independent Power Producers and Cogenerators: Independent
power producers and cogenerators located within the Company's service territory
provided approximately 203 MW of capacity to the Company in 1994. Capacity
from these sources is expected to remain at approximately 203 MW in 1995. The
Company has also contracted to purchase all excess power, currently estimated
to total 9.2 MW, from the Stony Brook project on an energy-only basis. The
Company had signed contracts for energy-only purchases totaling over 400 MW
from several other projects, but these projects were not built prior to
December 31, 1994, the expiration date of these contracts. In addition, the
Company was ordered by the PSC to enter into a contract with Mayflower Energy
Partners, L.P. ("Mayflower") incorporating the PSC's 1989 Long Run Avoided Cost
("LRAC") estimates. The contract, which the Company executed under protest,
would have required the Company to purchase, on an energy-only basis, power for
15 years from a 300 MW facility scheduled to begin commercial operation in
1995. The Company commenced a lawsuit against the PSC and the New York courts
ultimately annulled the PSC order requiring the Company to execute the
contract. The Company then notified Mayflower that it was exercising its right
to terminate the agreement as a result of Mayflower's failure to meet the
construction commencement milestone date. Subsequently, in October 1994,
Mayflower petitioned the PSC for a new contract based on a different LRAC
estimate. The Company opposed Mayflower's petition on the grounds that the
rates contained in the LRAC estimate requested by Mayflower were not just and
reasonable. In February 1995, the PSC denied Mayflower's petition.
Interconnections: Five interconnections allow for the
transfer of electricity between the Company and members of the NYPP and the New
England Power Pool. Energy from these sources is transmitted pursuant to
transmission agreements with Niagara Mohawk, NYPA, Northeast Utilities and
Consolidated Edison Company of New York, Inc. ("Con Edison") and displaces
energy which would otherwise be generated on the Company's system at a higher
cost. The capacity of these interconnections is utilized for (i) the
requirements of Con Edison, a co-owner with the Company of three of these
interconnections, (ii) the requirements on Long Island of NYPA, the owner of
one of these interconnections, (iii) the Company's purchases from NYPA and
other utilities and (iv) the transmission of the Company's share of power from
Nine Mile Point 2.
Conservation Services: In 1993, the Company filed a Modified
Demand Side Management ("DSM") Plan with the PSC to support the objectives of
the Company's electric rate case filed in December 1993. Under this modified
plan, the Company proposed a substantially lower level of spending than that
initially approved for 1994. The PSC did not approve the Company's proposed
DSM program, but instead issued a ruling in July 1994 which dictated energy
savings targets that were greater than those originally proposed by the
Company. Specifically, the targets for the Company's DSM programs amounted to
a 161.3 MW reduction in coincident peak demand and an annualized energy savings
of 702.6 gigawatthours ("GWh") by December 31, 1994. The Company was
successful in its DSM efforts.
In 1995, the Company intends to continue to carefully manage
DSM expenditures and more fully transform DSM into a strategic marketing tool
which can be used to position the Company for the future. In these efforts,
the Company will act to further increase the emphasis on education and
information programs and further decrease its emphasis on utility rebate
payments. In addition, financing programs and other cost sharing arrangements
will be stressed as a means to reduce DSM program costs. Finally, DSM programs
will be redesigned to enhance the Company's competitive position through the
offering of programs and services to the Company's customers and programs which
promote the efficient use of electricity, including energy-efficient load
growth.
1989 Settlement and Electric Rates
General: On February 28, 1989, the Company and the State of
New York (by its Governor) entered into an agreement (the "1989 Settlement")
settling certain issues relating to the Company and providing for, among other
matters, the return of the Company to financial health, the transfer of the
Shoreham Nuclear Power Station ("Shoreham") to LIPA and Shoreham's subsequent
decommissioning.
The Rate Moderation Agreement: The Rate Moderation Agreement
("RMA"), a constituent document of the 1989 Settlement approved by the PSC,
created an asset known as the Financial Resource Asset (the "FRA") and provides
for its full recovery. The FRA has two components, the Base Financial
Component (the "BFC") and the Rate Moderation Component (the "RMC").
The BFC, as initially established, represented the present
value of the future net-after-tax cash flows which the RMA provided the Company
for its financial recovery. Similar to plant investments, the BFC was granted
rate base treatment under the terms of the RMA and is included in the Company's
electric rates through amortization over 40 years on a straight-line basis. At
December 31, 1994, the BFC amounted to $3.5 billion, net of accumulated
amortization.
The RMC reflects the difference between the Company's revenue
requirements under conventional ratemaking and the revenues resulting from the
implementation of the rate moderation plan provided for in the RMA. Prior to
December 31, 1992, the RMC had increased as the difference between revenues
resulting from the implementation of the rate moderation plan provided for in
the RMA and revenue requirements under conventional ratemaking, together with a
carrying charge equal to the allowed rate of return on rate base, was deferred.
The RMC had provided the Company with a substantial amount of non-cash earnings
since the effective date of the 1989 Settlement through December 31, 1992,
because the revenues provided under the RMA were less than the revenues
required under conventional ratemaking. At December 31, 1992, the RMC balance
was $652 million. Subsequent to December 31, 1992, the RMC balance decreased
as revenues resulting from the operation of the rate moderation plan exceeded
revenue requirements under conventional ratemaking. At December 31, 1994 and
1993, the RMC balance was $463 million and $610 million, respectively.
Electric Rates: The RMA contemplated, among other objectives,
a series of rate increases designed to restore the Company to financial health.
Pursuant to the RMA, the Company received electric rate increases of 5.4%
effective February 18, 1989 and 5.0% for each of the rate years that began on
December 1, 1989 and December 1, 1990. In 1991, the PSC approved annual
electric rate increases of 4.15%, 4.1% and 4.0% effective on December 1 of
1991, 1992 and 1993, respectively.
In December 1993, the Company filed a three-year electric rate
plan with the PSC for the period beginning December 1, 1994 (the "Electric Rate
Plan"). The Electric Rate Plan, which may be approved, modified or rejected by
the PSC, requests an allowed rate of return on common equity of 11.0% and
provides for zero percent base rate increases in years one and two of the plan
and an overall rate increase of 4.3% in the third year. Although base electric
rates would be frozen during the first two years of the Electric Rate Plan,
annual rate increases of approximately 1% are expected to result in years one
and two from the operation of the Company's fuel cost adjustment ("FCA")
mechanism. The FCA captures, among other things, amounts to be recovered from
or refunded to ratepayers in excess of $15 million which result from the
reconciliation of revenue, certain expenses, and earned performance incentive
components as prescribed by the Long Island Lighting Company Ratemaking and
Performance Plan.
The PSC had been expected to issue a final order on the
Company's Electric Rate Plan before November 29, 1994, the date that the
statutory suspension period was initially scheduled to terminate. However, in
order to accommodate further settlement negotiations in the proceedings, the
Company had requested extensions through April 1995, which were granted by the
PSC.
In the past, the PSC has taken actions consistent with the
recovery from ratepayers of the 1989 Settlement-deferred charges provided by
the RMA. The PSC has granted the Company six of the eleven electric rate
increases contemplated by the RMA and has also publicly confirmed its
commitment to the effectuation of the 1989 Settlement. Although the ultimate
outcome of the Electric Rate Plan cannot be predicted, the Company expects that
any PSC order will be consistent with the provisions of the RMA respecting the
recovery of the FRA and other 1989
Settlement-deferred charges.
For additional information respecting the 1989 Settlement and
electric rates, see the discussion under the heading "Management's Discussion
and Analysis of Financial Condition and Results of Operation for the Year Ended
December 31, 1994" and Notes 1, 2 and 3 of Notes to Financial Statements for
the Year Ended December 31, 1994.
Competitive Environment
For a discussion of the competitive issues facing the Company,
see "Management's Discussion and Analysis of Financial Condition and Results of
Operations For the Year Ended December 31, 1994."
SHOREHAM DECOMMISSIONING:
Pursuant to the 1989 Settlement, the Company transferred
Shoreham and the Company's possession-only license for Shoreham to LIPA in
February 1992, following a decision by the NRC that approved the transfer. In
June 1992, the NRC issued an order authorizing LIPA to decommission Shoreham.
During the fourth quarter of 1994, LIPA completed the decommissioning subject
to the NRC's completion of a review of radiological measurements and its
termination of the possession-only license, which is currently expected by
mid-1995.
Under an agreement entered into as part of the 1989 Settlement
(the "Amended and Restated Asset Transfer Agreement"), the Company is required
to reimburse LIPA for any of its costs associated with the decommissioning of
Shoreham. The Site Cooperation and Reimbursement Agreement (the "Site
Agreement") entered into by the Company and LIPA describes the payment by the
Company of LIPA's and NYPA's expenses attributable to the transfer, ownership,
possession, maintenance and decommissioning of Shoreham, including certain
taxes and payments-in-lieu-of-taxes ("PILOTS") with respect to the Shoreham
site. The Site Agreement also governs, among other things, the conduct of the
parties and of NYPA, and their access to facilities and properties at the
Shoreham site.
At December 31, 1994, Shoreham post settlement costs totaled
approximately $923 million (net of accumulated amortization of approximately
$56 million). The $923 million consists of $429 million of property taxes and
PILOTS and $494 million of decommissioning costs, fuel disposal costs and all
other costs incurred at Shoreham after June 30, 1989, net of Shoreham salvage
proceeds of approximately $44 million. The Company currently estimates that,
during 1995, an additional $13 million of post settlement costs (other than
PILOTS and finance charges) will be incurred. The precise amount of taxes and
PILOTS that must be paid is the subject of the litigation described in Item 3,
"Legal Proceedings -- Shoreham."
The PSC has determined that all costs associated with Shoreham
which are prudently incurred by the Company subsequent to the effectiveness of
the 1989 Settlement are decommissioning costs. The RMA provides for recovery
of such costs through electric rates over the balance of a 40-year period
ending 2029. In addition, pursuant to the RMA, the Company reflects the costs
of the nuclear fuel related to Shoreham as a deferred charge to be recovered
from ratepayers. The Company is required under the Amended and Restated Asset
Transfer Agreement to reimburse LIPA for any of its costs associated with the
storage and disposal of Shoreham's fuel, which was completed in 1994, and is
allowed to recover these reimbursed amounts from its ratepayers as well.
For additional information respecting the 1989 Settlement, see
Notes 1 and 2 of Notes to Financial Statements for the Year Ended December 31,
1994.
GAS OPERATIONS:
General
In 1994, the Company was an active participant in proceedings
before FERC in various matters in an effort to reduce interstate pipeline
charges, improve operational tariffs and to mitigate any adverse impact from
interstate pipeline filings on the Company's customers. In addition, in 1995,
the Company will actively participate in the proceedings before the PSC in an
attempt to influence the establishment of the new competitive natural gas
marketplace within the State of New York.
Gas System Requirements
At year-end 1994, the Company had a total of 449,316 firm gas
customers, compared to 445,830 at year-end 1993 and 441,580 at year-end 1992.
Of the 1994 year-end total, 277,077 were space heating customers. Total firm
sales in 1994 were 58,889,386 Dth, compared to 59,182,674 Dth in 1993. The
maximum daily sendout experienced on the Company's gas system in 1994 was
585,227 Dth on January 19, 1994. The forecasted maximum daily sendout for the
1994-95 winter season (November 1 - March 31) is 608,000 Dth, representing 86%
of the Company's maximum daily firm operating supply capability of 705,597 Dth
for this period. Based on this forecasted amount, the Company should have a
peak day surplus of 97,597 Dth of firm supply including peak shaving capability
for the 1994-95 winter season. The Company recovers the costs of its gas
supply from both its firm and interruptible customers through provisions in the
Company's rate schedules.
Continuing its recent efforts to expand its base of customers,
the Company is emphasizing residential and commercial gas marketing. In
particular, new market segments and new uses for natural gas are being sought,
especially as a replacement for diesel fuel. The technology for natural gas as
a vehicular fuel is becoming commercially viable. Natural gas can be cost
effective if used in high volume for public transportation and public works
vehicles. In addition to the Long Island Bus Company (formerly the
Metropolitan Suburban Bus Authority), the Company has worked with local
municipalities in testing the viability of converting various vehicle types to
compressed natural gas as well as in designing and installing refueling
stations. Projects currently under consideration could ultimately displace
several thousand gallons of diesel fuel per day.
Gas Transportation and Supply
The proceedings before FERC, developing out of its Order No.
636, have resulted in a regulatory "unbundling" of the gas supply,
transportation and storage services that for decades had been provided by the
nation's natural gas pipelines. As a result of Order No. 636, pipelines, for
the most part, no longer act as sales agents to bundle the mix of services from
the producers and other interstate pipelines. Local distribution companies
("LDCs") must now make arrangements for gas supplies and gas storage directly
with producers, marketers, pipelines and the owners of storage facilities. In
addition, each LDC must now also make separate transportation arrangements with
each pipeline in the path between the supplier and the LDC's citygate and not
merely with the nearest pipeline connecting to the LDC's system. Prior to the
effective date of Order No. 636, LDCs had purchased their gas supplies at the
citygate from those pipelines serving their territories. The citygate is
generally the location where the interstate pipeline meets the local
distribution company's system. The Company shares common citygate facilities,
known as the New York Facilities, with Con Edison and the Brooklyn Union Gas
Company. The Company's principal pipeline suppliers are Transcontinental Gas
Pipe Line Corporation ("Transcontinental"), Texas Eastern Transmission
Corporation ("Texas Eastern"), CNG Transmission Corporation ("CNG"), Tennessee
Gas Pipeline Company ("Tennessee") and the Iroquois Gas Transmission System
("Iroquois"). Through its wholly-owned subsidiary, the Company is a general
partner in Iroquois, with an equity share of 1%. The Company, through a
wholly-owned subsidiary, had been a 3-1/3% equity partner in the Liberty
Pipeline Company ("Liberty"). However, as a result of a re-evaluation of its
gas supply needs, in May 1994, the Company notified the other Liberty partners
of its withdrawal from the Liberty pipeline partnership.
Gas Transportation: The Company's gas transportation capacity
for meeting its 1994-95 winter season requirements is provided from a portfolio
of year-round, winter seasonal, storage and cogenerator services summarized
below:
[Download Table]
1994-95 Winter Peak-Day Transportation Capacity:
-----------------------------------------------
Type of Supply Dth Per Day
-------------- -----------
Year-Round 258,492
Winter Seasonal 2,726
Storage 287,839
Other Deliveries 30,840
-------
Total 579,897
=======
Year-Round Pipeline Firm Transportation: The Company has
318,692 Dth per day of year-round pipeline firm transportation capacity
provided by four interstate pipeline companies: Transcontinental, Texas
Eastern, Tennessee and Iroquois. For the 1994-1995 winter season, options to
purchase 60,200 Dth per day of capacity have been granted to off-system markets
leaving a total of 258,492 Dth available to meet system peak-day requirements.
Winter Seasonal Pipeline Firm Transportation: The Company has
winter seasonal pipeline firm transportation capacity on Transcontinental
amounting to 2,726 Dth per day available through March 31, 1995.
Storage: The Company also has long-term firm storage services
to meet higher winter demand which provide a total operating supply of
approximately 287,839 Dth per day with a total capacity of 23,505,043 Dth for
the winter period. Of these totals, 277,589 Dth per day, or a total capacity
of 22,268,043 Dth, is provided by gas storage fields at Leidy, Pennsylvania,
and 10,250 Dth per day, or a total capacity of 1,237,000 Dth, is provided by a
gas storage field in upstate New York operated by Honeoye Storage Corporation
("Honeoye"). The Company currently owns 23- 1/3% of the common stock of
Honeoye. In addition, the Company has the right to request 812,500 Dth in the
winter period from a cogeneration facility with the obligation to return
quantities in kind during the following summer period.
The Company also contracts for storage capacity in a facility
in Louisiana near sources of supply and pipeline transportation. Up to 50,687
Dth per day can be withdrawn with a total storage capacity of 4,459,220 Dth
available at this facility. While this facility provides the Company with
greater security of supply and enhanced operational flexibility in meeting
peak-day requirements, the Company has no related firm pipeline transportation
agreement for these supplies. Therefore, to access gas from this storage, the
Company must curtail the transportation of some of its firm contract supply.
Other Deliveries: The Company has contract rights with NYPA
to receive a total of 900,000 Dth during a continuous 100 day period between
November 1 and March 31 of each winter season at a daily rate not to exceed
30,840 Dth per day.
Gas Supply: The Company's gas supplies for the 1994-95 winter
season are provided from a portfolio of year-round, winter seasonal, storage
and peak shaving supplies summarized below.
Year-Round Firm Supply: Of the 213,469 Dth of firm supplies,
83,575 Dth are Canadian and 129,894 Dth are domestic. The Company owns 2.7% of
the common stock of Boundary Gas, Inc., ("Boundary"), a corporation formed with
15 other gas utility companies to act as a purchasing agent for the importation
of natural gas from Canada. The Company obtains 2,470 Dth per day of its
long-term firm Canadian supply from this source. Gas supplies to use 105,223
Dth per day of the remaining year-round pipeline firm transportation capacity
are purchased by the Company in both the seasonal and monthly spot markets.
Winter Seasonal Firm Supply: The Company also contracts for
firm seasonal supply of 90,223 Dth delivered during the period November 1 -
March 31 of each year from a number of winter seasonal suppliers.
Peak Shaving: The Company has its own peak shaving supplies
to meet its requirements on excessively cold winter days. They include a
liquefied natural gas plant with a storage capacity of approximately 620,000
Dth of gas and vaporization facilities which provide 103,300 Dth per day to the
peak-day capability of the Company's system. In addition, the Company has
propane facilities that produce 22,400 Dth per day of peak shaving with a
storage capacity of approximately 100,000 Dth.
Gas Rates
In December 1993, the PSC approved a three-year gas rate
settlement between the Company and the Staff of the PSC. The gas rate
settlement provides that the Company receive, for each of the rate years
beginning December 1, 1993, 1994 and 1995, annual gas rate increases of 4.7%,
3.8% and 2.8%, respectively. In the determination of the revenue requirements
for the gas rate settlement, an allowed rate of return on equity of 10.1% was
used. The gas rate decision also provides for earnings in excess of a 10.6%
return on equity in any of the three rate years covered by the settlement to be
shared equally between the Company's firm gas customers and its shareowners.
For additional information respecting gas rates, see Note 3 of Notes to
Financial Statements for the Year Ended December 31, 1994.
Other Activities
The unbundling of gas transportation activities and the need
for local distribution companies to negotiate directly with producers and other
suppliers and with pipelines has provided the Company with new business
opportunities. These new opportunities include providing gas to
non-traditional markets including LDCs and end-users from Mississippi to
Connecticut. In 1994, total activities in this area generated $26 million in
revenue. The profit realized from this activity is shared 85%-15% between the
Company's firm gas customers and shareowners, respectively.
Recovery of Transition Costs
Transition costs are the costs associated with unbundling the
pipelines' merchant services in compliance with Order No. 636. They include
pipelines' unrecovered gas costs and the costs that pipelines incur as a result
of reforming or terminating their gas supply contracts. In order to recover
transition costs, pipelines must demonstrate to FERC that such costs were
attributable to FERC Order No. 636 and that they were prudently incurred.
While the Company has challenged, on both eligibility and prudence grounds, its
suppliers' pipelines' efforts to recover their claimed transition costs, the
Company presently estimates that its total transition costs will be
approximately $9 million. As of December 31, 1994, the Company has paid
approximately $7 million of these transition costs and is currently collecting
these costs from its gas customers in rates.
ENVIRONMENT:
General
The Company is subject to federal, state and local laws and
regulations dealing with air, water and land quality and other environmental
matters. It is not possible to ascertain with certainty if or when the various
required governmental approvals for which applications have been made will be
issued, whether, except as noted below, additional facilities or modifications
of existing or planned facilities will be required or, generally, what effect
existing or future controls may have upon Company operations. Except as set
forth below and in Item 3 - "Legal Proceedings", no material proceedings have
been commenced or, to the knowledge of the Company, are contemplated
by any federal, state or local agency against the Company, nor is the Company a
defendant in any material litigation with respect to any matter relating to the
protection of the environment.
In 1995 and 1996, in order to comply with environmental
regulations, the Company anticipates capital expenditures of approximately $6.0
million and $3.5 million, respectively.
Air
Federal, state and local regulations affecting new and
existing electric generating plants govern, among other emissions, sulfur
dioxide and nitrogen oxide ("NOx") and, in the future, hazardous air
pollutants.
The laws governing the sulfur content, by weight, of the fuel
oil being burned by the Company in compliance with the United States
Environmental Protection Agency ("EPA") approved Air Quality State
Implementation Plan ("SIP") are administered by the New York State Department
of Environmental Conservation ("DEC"). The Company does not expect to incur
any costs to satisfy the 1990 amendments to the federal Clean Air Act (the
"Act") with respect to the reduction of sulfur dioxide emissions, since the
Company already uses fuel with acceptable low levels of sulfur.
During 1994, the Company spent approximately $6.4 million in
order to comply with the Act. These expenditures were necessary to meet
continuous emissions monitoring requirements and Phase I NOx reduction
requirements under the Act.
The Company expects that it will have to expend approximately
$1 million in 1995 to meet continuous emission monitoring requirements and to
meet Phase I NOx reduction requirements. In order to generate 210 tons of NOx
reduction credits already under contract for sale to a third party, the Company
anticipates spending $2.5 million in 1995 and $1.9 million in 1996 for earlier
than required NOx reduction systems. Subject to requirements that are expected
to be promulgated in forthcoming regulations, the Company estimates that it may
be required to spend an additional $80 million (net of NOx credit sales) by
2003 to meet Phase II and Phase III NOx reduction requirements. In an effort
to minimize anticipated NOx reduction requirements, the Company is engaged in a
$7 million research and development project along with several co-funding
organizations to demonstrate an innovative NOx reduction technology at its E.
F. Barrett Power Station. The Company is committed to fund $3.6 million of the
project costs. Through 1994, approximately $5 million has been expended by all
of the co-funders. It is anticipated that the remaining $2 million will be
spent in 1995. In addition, the Company anticipates that it may be required to
spend approximately $24 million by 1999 to meet potential requirements for the
control of hazardous air pollutants from power plants. The Company believes
that all of the above costs will be recoverable in rates.
Electromagnetic fields ("EMF") occur naturally and also are
produced wherever there is electricity. These fields exist around power lines
and other utility equipment. The Company is in compliance with all applicable
regulatory standards and requirements concerning EMF. The Company also
monitors scientific developments in the study of EMF, contributes to funding
for research efforts and is actively involved in customer and employee outreach
programs to inform the community of EMF developments as they occur. Although
an extensive body of scientific literature has not shown an unsafe exposure
level or a causal relationship between EMF exposure and adverse health effects,
concern over the potential for adverse health effects will likely continue
without final resolution for some time.
To date, the Company has not been involved in any matter that
alleged such a causal relationship. However, four residential property owners
have initiated lawsuits against the Company alleging that the existence of EMF
has diminished the value of their homes. These actions are in the preliminary
stages of discovery and their outcome is uncertain. The Company is currently
unable to predict the impact, if any, that EMF-related matters will have on its
financial position.
Water
Under the federal Clean Water Act and the New York State
Environmental Conservation Law, the Company is required to obtain a State
Pollutant Discharge Elimination System permit to make any discharge into the
waters of the United States or New York State. The DEC has the jurisdiction to
issue those permits and their renewals and has issued permits for the Company's
generating units. The permits allow the continued use of the circulating water
systems which have been determined to be in compliance with State Water Quality
Standards. The permits also allow for the continued use of the chemical
treatment systems. The Company expects to upgrade certain underground tanks
and piping systems in 1995 in order to comply with federal and local
regulations.
Land
The DEC has indicated to New York State utilities that it may
require all such utilities to investigate and, where necessary, remediate their
former manufactured gas plant sites. The Company is the owner of six pieces of
property on which the Company or certain of its predecessor companies produced
manufactured gas. Although the exact amount of the Company's clean-up costs
cannot yet be determined, based on the findings of investigations at two of
these six sites, preliminary estimates indicate that it may cost approximately
$35 million to clean up all of these sites over the next five to ten years.
Accordingly, the Company has recorded a $35 million liability and has also
recorded a $35 million regulatory asset to reflect its belief that the PSC will
provide for the future recovery of these costs as it has for other New York
State utilities. The Company has notified its former and current insurance
carriers that it seeks to recover from them certain of these cleanup costs.
However, the Company is unable to predict the amount of insurance recovery, if
any, that it may obtain.
The Company has been notified by the EPA that it is one of
many potentially responsible parties ("PRPs") that may be liable for the
remediation of a licensed disposal site located in Philadelphia, Pennsylvania,
and operated by Metal Bank of America. The Company and nine other PRPs, all of
which are public utilities, have completed a Remedial Investigation and
Feasibility Study which is currently being reviewed by the EPA. The level of
remediation required will be determined when the EPA issues its decision,
currently expected in May 1995. The Company currently anticipates that the
total cost to remediate this site will be between $14 million and $30 million.
The Company has recorded a liability of $1.1 million representing its estimated
share of the cost to remediate this site. The Company believes that any cost
incurred to remediate this site will be recoverable through rates.
The Company has also been named a PRP for disposal sites in
both Kansas City, Kansas, and Kansas City, Missouri. The Company is
investigating allegations that it had previously stored or made agreements for
the disposal of polychlorinated biphenyls ("PCBs") or items containing PCBs at
these sites. The Company is currently unable to determine its share of the
cost to remediate these sites or the impact, if any, on the Company's financial
position. The Company believes that any costs incurred to remediate these
sites will be recoverable through rates.
In March 1989, the Company was notified that it was a PRP for
a landfill in Port Washington, Long Island. The Company does not believe that
it has contributed to the contamination of the site and has declined the EPA's
requests to participate in the investigation and remediation activities at the
site. The Company has not received further communications regarding this site.
The Company is in the process of entering into an
Administrative Order on Consent with the DEC to remediate lead contaminated
soils at a former distribution gas holder site in Inwood, New York that
contained a gas holder coated with lead paint. Based on the current cleanup
objectives, remediation costs are estimated at $2 million and are expected to
be incurred from 1995 to 1996.
As a result of a leak in a fluid filled electrical cable in
August 1994, the Company is required to remediate certain soil locations in
North Hills, Long Island that were impacted by a release of insulating fluid
from
the cable. The preliminary estimated cleanup costs, expected to be incurred
from 1995 to 1996, range from $0.5 to $3.2 million. The Company has initiated
cost recovery actions against third parties it believes are responsible for
causing the cable leak, the outcome of which is uncertain.
For information concerning environmental litigation, see Item
3 -- "Legal Proceedings--Environmental."
Nuclear Waste
Under the federal Low Level Radioactive Waste Policy Amendment
Act of 1985, New York was required, by January 1, 1993, to have arranged for
the disposal of all low level, radioactive waste generated within the state or,
in the alternative, contracted for the disposal of waste at an operating
facility outside the state. Failure to do so would require New York to forfeit
to the generators of waste in the state the rebate of a portion of the
surcharges paid by such generators for the disposal of waste at operating
facilities outside the state. New York's contract with the State of South
Carolina for the disposal of all low level radioactive waste (except mixed
wastes) expired in June 1994.
Under the Amended and Restated Asset Transfer Agreement,
discussed under the heading "Shoreham Decommissioning," LIPA is responsible for
the disposal of waste associated with the decommissioning of Shoreham, although
such costs will be paid by the Company and recovered through electric rates.
All low level radioactive waste associated with the decommissioning of Shoreham
was sent to South Carolina for disposal prior to the expiration of the disposal
contract.
All low level radioactive waste generated at the Nine Mile
Point 2 site since June 1994 is being temporarily stored at the Nine Mile site.
A waste management program has been put in place that will properly handle
interim on-site storage of low level radioactive waste for at least ten years,
if required. All costs associated with temporary storage and ultimate disposal
are expected to be recovered in rates.
In addition, Niagara Mohawk, on behalf of the Nine Mile Point
2 cotenants, has entered into a contract with DOE for the permanent storage of
Nine Mile Point 2 spent nuclear fuel. The Company reimburses Niagara Mohawk
for its 18% share of the cost under the contract at a rate of $1.00 per
megawatt hour of net generation less a factor to account for transmission line
losses. The Company is collecting its portion of this fee from the Company's
ratepayers. However, progress in developing a permanent DOE repository for
such high level radioactive material has been slow and it is unlikely that the
DOE's latest projections for opening a facility in 2010 can be met. In the
interim, DOE is proposing to begin accepting some spent fuel from the electric
utility industry as early as 1998 at a proposed Monitored Retrievable Storage
("MRS") facility. In view of the very limited progress made to date, it is
unlikely that this facility will begin operation in 1998. A more probable date
for operation of the MRS facility cannot be accurately determined at this time.
Currently, all spent nuclear fuel from Nine Mile Point 2 is being stored on
site. The present licensed storage capacity for Nine Mile Point 2 is expected
to be sufficient to meet its needs so that storage alternatives are not
believed to be needed at this time. The Company does not anticipate that the
possible unavailability of a DOE facility in 1998 will inhibit the operation of
Nine Mile Point 2.
THE COMPANY'S SECURITIES:
General
The Company's securities are rated by Moody's Investors
Service, Inc., Standard and Poor's Ratings Group, Fitch Investors Service, Inc.
and Duff and Phelps, Inc. For information relating to the ratings of the
Company's securities, see the discussion under the heading "Management's
Discussion and Analysis of Financial Condition and Results of Operations for
the Year Ended December 31, 1994."
The G&R Mortgage
The Company's General and Refunding Indenture dated June 1,
1975 (the "G&R Indenture" or "G&R Mortgage") is a lien upon substantially all
of the Company's properties. The lien of the G&R Mortgage is currently
subordinate to the lien of the Company's Indenture of Mortgage and Deed of
Trust dated September 1, 1951 (the "Indenture of Mortgage" or "First
Mortgage"). The G&R Mortgage will become the Company's senior mortgage in
1997, the year in which the last of the currently outstanding non-pledged First
Mortgage Bonds mature. Outstanding at December 31, 1994 were approximately $2
billion of General and Refunding Bonds (the "G&R Bonds") and $100 million of
First Mortgage Bonds, excluding $1.3 billion of First Mortgage Bonds which are
pledged with the G&R Trustee as additional security for the G&R Bonds (the
"Pledged Bonds"). Additional information concerning the Company's G&R Mortgage
and the First Mortgage is discussed below and in Note 7 of Notes to Financial
Statements for the Year Ended December 31, 1994.
Under the G&R Mortgage, the Company may issue G&R Bonds on the
basis of either matured or redeemed G&R Bonds and First Mortgage Bonds (other
than Pledged Bonds) or on the basis of the Bondable Value of Property Additions
("BVPA"). Generally, when issuing G&R Bonds, the Company must satisfy a
mortgage interest coverage requirement (the "G&R Mortgage Interest Coverage").
The G&R Mortgage Interest Coverage requires that the Net Earnings available for
interest for any 12 consecutive calendar months within the 15 consecutive
calendar months preceding the issuance of the G&R Bonds must be equal to at
least two times the stated annual interest payable on outstanding G&R Bonds and
Prior Lien Bonds (other than Pledged Bonds), including any new G&R Bonds.
Under the G&R Mortgage Interest Coverage, the Company would currently be able
to issue approximately $4.1 billion of additional G&R Bonds based upon: (i)
earnings for the 12 months ended December 31, 1994 and (ii) an assumed interest
rate of 10% for such additional G&R Bonds. A change of 1/8 of 1% in the
assumed interest rate of such G&R Bonds would result in a change of
approximately $51 million in the amount of such G&R Bonds that the Company
could issue. The maximum amount of additional G&R Bonds which the Company is
currently able to issue on the basis of either matured or retired G&R Bonds and
First Mortgage Bonds (other than Pledged Bonds) and on the basis of the BVPA is
approximately $520 million.
The Company believes that, based upon currently scheduled
redemptions and maturities, it will have sufficient retired G&R Bonds and First
Mortgage Bonds for the foreseeable future to satisfy the requirements of the
G&R Sinking Fund or to withdraw with retired G&R Bonds and First Mortgage Bonds
any cash that may be deposited to satisfy the Sinking Fund requirements. The
Sinking Fund requires the Company to pay $26 million or to certify a like
amount of retired G&R Bonds and First Mortgage Bonds on or before June 30,
1995. The Company is planning to satisfy this requirement in 1995 with retired
G&R Bonds. In addition, the Company may use Property Additions to satisfy this
requirement.
The Maintenance Fund covenant under the G&R Mortgage requires
that the aggregate amount of Property Additions added subsequent to December
31, 1974 must be, as of the end of each calendar year subsequent to 1974, at
least equal to the cumulative Provision for Depreciation (as defined in the G&R
Mortgage) from December 31, 1974. The G&R Mortgage requires cash (or retired
G&R Bonds or retired First Mortgage Bonds) to be deposited to satisfy the
Maintenance Fund requirement only when such cumulative Provision for
Depreciation exceeds such aggregate amount of Property Additions. As of
December 31, 1994, the amount of such cumulative Property Additions calculated
pursuant to the G&R Mortgage was approximately $9.7 billion, including
approximately $5.5 billion of Property Additions attributable to Shoreham.
Also, as of December 31, 1994, the amount of the cumulative Provision for
Depreciation, similarly calculated, was approximately $1.6 billion. The
Company anticipates that the aggregate amount of Property Additions will
continue to exceed the cumulative Provision for Depreciation.
The First Mortgage
Under the provisions of the G&R Mortgage, the Company may not
issue any additional bonds under the Company's First Mortgage other than
Pledged Bonds which are required, concurrently with the issuance of each new
series of G&R Bonds, to be deposited with the G&R Trustee. The issuance of any
such Pledged Bonds does not create additional indebtedness. The coverage
requirements of the First Mortgage and the Company's ability to issue
additional Pledged Bonds do not restrict the Company's ability to issue
additional G&R Bonds. Of the approximately $1.4 billion of First Mortgage
Bonds outstanding at December 31, 1994, $1.3 billion, or 93%, were Pledged
Bonds. After satisfying the 1994 Depreciation Fund and Sinking Fund
requirements discussed below, the Company expects that it will issue additional
Pledged Bonds if it issues additional G&R Bonds prior to the maturity, in 1997,
of the last of the outstanding non- pledged First Mortgage Bonds.
The First Mortgage requires the Company to pay the First
Mortgage Trustee by June 30 of each year cash equal to 1% of all previously
issued First Mortgage Bonds (excluding bonds issued on the basis of retired
bonds). Currently, the annual First Mortgage Sinking Fund requirement is
approximately $21 million. The Company expects to satisfy this requirement
prior to June 30, 1995, with retired First Mortgage Bonds. The annual Sinking
Fund requirement is not expected to change, because of restrictions in the G&R
Mortgage, until and unless the Company issues additional G&R Bonds. The
Company expects to be able to satisfy the Sinking Fund requirement in 1996, the
last year in which this requirement must be met, with cash, available Property
Additions or retired First Mortgage Bonds which become available through
scheduled maturities.
The Depreciation Fund covenant of the First Mortgage requires
that the Company pay to the First Mortgage Trustee by June 30 of each year cash
(which may be withdrawn up to the amount of Gross Bondable Additions and
retired First Mortgage Bonds made the basis for such withdrawal) equal to the
greater of (a) the amount actually charged on the Company's books as a utility
operating revenue deduction for the preceding calendar year for depreciation,
depletion, obsolescence, retirements and amortization of the Company's Utility
Plant ("Book Depreciation") or (b) an amount equal to (i) 15% of gross
operating revenues (less the cost of electricity and gas purchased for resale)
from Utility Plant for such year less (ii) the amount actually expended for
maintenance of Utility Plant during such year ("Revenue Depreciation"). Since
the oil crisis of the 1970s, Revenue Depreciation in each year has been greater
than Book Depreciation for such year. The Revenue Depreciation requirement for
1994 was approximately $239 million. Instead of paying cash to satisfy this
Depreciation Fund requirement, the First Mortgage permits the Company to
deliver First Mortgage Bonds or certify Property Additions. The Company
expects to satisfy the 1994 requirement by June 30, 1995, using a combination
of First Mortgage Bonds and Property Additions. The Company presently plans,
assuming that its expenditures for capital improvements are approximately $250
million annually and notwithstanding that G&R Bonds may be issued which would
require, in turn, the issuance of First Mortgage Bonds to be pledged, that it
will have adequate Property Additions and sufficient retired First Mortgage
Bonds, including Pledged Bonds, to satisfy the Depreciation Fund requirements
in 1996, the last year in which this requirement must be met.
Unsecured Debt
The Company's First Mortgage, its G&R Mortgage and its
Restated Certificate of Incorporation do not contain any limitations upon the
issuance of unsecured debt. The Company's unsecured debt consists of
Debentures and certain tax-exempt securities.
The Company's Debenture Indenture, dated as of November 1,
1986, as supplemented, and its Debenture Indenture, dated as of November 1,
1992, as supplemented, (together, the "Debenture Indentures") each provide for
the issuance of an unlimited amount of Debentures to be issued in amounts that
may be authorized from time to time in one or more series. The Debentures are
unsecured and rank pari passu with all other unsecured indebtedness of the
Company subordinate to the obligations secured by the Company's two mortgages.
Currently, there are approximately $2.3 billion of Debentures outstanding.
As of December 31, 1994, the Company had outstanding
approximately $867 million principal amount of promissory notes, securing $2
million of tax-exempt Industrial Development Revenue Bonds ("IDRBs"),
approximately $215 million of tax-exempt Pollution Control Revenue Bonds
("PCRBs") and $650 million of tax-exempt Electric Facility Revenue Bonds
("EFRBs"). Of these amounts, $17 million issued in 1982, $150 million issued
in 1985 (the "1985 PCRBs"), $100 million issued in 1993 (the "1993 EFRBs") and
$50 million issued in 1994 (the "1994 EFRBs") are subject to periodic tenders
by the holders of the tax-exempt bonds. The 1985 PCRBs, 1993 EFRBs and 1994
EFRBs are supported by letters of credit pursuant to which the letter of credit
banks have agreed to pay the principal, interest and premium, if applicable, on
any tendered 1985 PCRBs, 1993 EFRBs or 1994 EFRBs, in the aggregate, up to
approximately $163 million, $109 million, and $54 million respectively, in the
event of default. These letters of credit expire on March 16, 1996, November
17, 1996 and October 26, 1997, respectively. The obligations of the Company to
reimburse the letter of credit banks supporting the 1985 PCRBs, the 1993 EFRBs
and the 1994 EFRBs are unsecured. Each of the IDRBs, the PCRBs and the EFRBs
have been issued by the New York State Energy Research and Development Authority
("NYSERDA").
See Note 7 of Notes to Financial Statements for the Year Ended
December 31, 1994 for additional information respecting the Company's
outstanding debt securities.
Equity Securities
Preferred Stock: The Company's Restated Certificate of
Incorporation provides that the Company may not issue additional Preferred
Stock unless the net earnings of the Company available for payment of interest
on its debt after depreciation and all taxes for any 12 consecutive calendar
months within the 15 calendar months preceding the month of issuance are at
least 1.50 times the aggregate of the annual interest charges and dividend
requirements on the debt and Preferred Stock to be outstanding immediately
after the issuance of such Preferred Stock (the "Earnings Ratio"). The Company
currently satisfies the Earnings Ratio and could issue up to approximately $250
million of Preferred Stock. When the proceeds from the sale of the Preferred
Stock to be issued are used to redeem outstanding Preferred Stock, the
requirement to satisfy the Earnings Ratio is not applicable if the dividend
requirement and the requirements for redemption in a voluntary liquidation of
the Preferred Stock to be issued do not exceed the respective amounts for the
Preferred Stock which is to be retired. Additional Preferred Stock may also be
issued beyond amounts permitted under the Earnings Ratio with the approval of
at least two-thirds of the votes entitled to be cast by the holders of the
total number of shares of outstanding Preferred Stock.
Default in the payment of dividends on any shares of Preferred
Stock in an amount equivalent to or exceeding four full quarterly dividends for
any series of Preferred Stock entitles all holders of shares of Preferred
Stock, voting separately as a class and regardless of series, to elect a
majority of the Board of Directors of the Company. The remaining Directors are
elected by the holders of Common Stock. The right of holders of shares of
Preferred Stock to elect a majority of the Board of Directors ceases when and
if the Company ceases to be in default in the payment of its Preferred Stock
dividends. At that time, the terms of office of the Directors of the Company
elected by the holders of Preferred Stock terminate and the resulting vacancies
are to be filled by the vote of the remaining Common Stock Directors.
Preference Stock: Issuance of Preference Stock, which is
subordinate to the Company's Preferred Stock, but senior to its Common Stock,
with respect to declaration and payment of dividends and the right to receive
amounts payable on any dissolution, does not require satisfaction of a net
earnings test or any other coverage requirement, unless established by the
Board of Directors for one or more series of Preference Stock, prior to the
issuance of such series. No Preference Stock has been issued by the Company
nor does the Company currently plan to issue any Preference Stock.
Common Stock: The Company's Common Stock is listed on the New
York and Pacific Stock Exchanges, and is traded under the symbol "LIL". The
Board of Directors' current policy is to pay cash dividends on the Common Stock
on a quarterly basis. However, before declaring any dividends, the Company's
Board of
Directors considers, among other factors, the Company's financial condition,
its ability to comply with provisions of the Company's Restated Certificate of
Incorporation and the availability of retained earnings, future earnings and
cash.
EXECUTIVE OFFICERS OF THE COMPANY:
Current information regarding the Company's Executive
Officers, all of whom serve at the will of the Board of Directors, follows:
William J. Catacosinos: Dr. Catacosinos has served as
Chairman of the Board of Directors and Chief Executive Officer of the Company
since January 1984, and as a Director since December 1978. Dr. Catacosinos
also served as President of the Company from March 1984 to January 1987 and
from March 1994 to present. Dr. Catacosinos, 65, a resident of Mill Neck,
Long Island, earned a bachelor of science degree, a masters degree in business
administration and a doctoral degree in economics from New York University.
Dr. Catacosinos currently chairs the Executive Committee of the Company's Board
of Directors, and is a member of the boards of U.S. Life Corporation, Austin
International Communications, Edison Electric Institute, the Long Island
Association, the German American Chamber of Commerce, the Business Alliance for
a New, New York, and a member of the Advisory Committee of the Huntington
Township Chamber Foundation. He is the former chairman and chief executive
officer of Applied Digital Data Systems, Inc., Hauppauge, New York, a
manufacturer of computer and related products. Previously, Dr. Catacosinos
also served as chairman of the board and treasurer of Corometric Systems, Inc.
of Wallingford, Connecticut and as Assistant Director at Brookhaven National
Laboratory. He was also a member of the boards of Utilities Mutual Insurance
Co. from November 1985 through December 1994 and Ketema, Inc. from June 1988
through December 1994. Ketema is a diversified manufacturer of, among other
things, electrical and aerospace equipment. In compliance with Section 305(b)
of the Federal Power Act, Dr. Catacosinos had authorization from FERC to hold
the position of an officer or director of a public utility and at the same time
the position of an officer or director of a firm that supplies electrical
equipment to such public utility.
Theodore A. Babcock: Mr. Babcock was named Treasurer of the
Company on February 4, 1994. As Treasurer, he is responsible for Treasury
Operations, Debt Management, Trust Asset Management, Risk Management and
Remittance Processing. Mr. Babcock, 40, joined the Company in July 1992 as
Assistant Treasurer. He previously spent five years in the AMBASE Corporation
as an Assistant Vice President and was promoted in 1988 to Vice President and
Treasurer. Prior to AMBASE, Mr. Babcock spent 11 years with the Associated Dry
Goods Corporation where he was promoted to Assistant Treasurer and Director of
Corporate Treasury Operations in 1984. Mr. Babcock received a bachelor of
science degree in accounting from Manhattan College and a masters degree in
finance from Iona College.
James T. Flynn: Mr. Flynn was named Chief Operating Officer
of the Company on March 1, 1994 and continues in his position of Executive
Vice President which he assumed in April 1992. Mr. Flynn joined the Company in
October 1986 as Vice President of Fossil Production and later assumed the
position of Group Vice President, Engineering and Operations. Before joining
the Company, Mr. Flynn, 61, was general manager-Eastern Service Department for
General Electric. His career began as a member of General Electric's Technical
Marketing Program in 1957. He holds a bachelor of science degree in
mechanical engineering from Bucknell University and is a Licensed Professional
Engineer in the State of Pennsylvania.
Joseph E. Fontana: Mr. Fontana was named Controller of the
Company on October 1, 1994. Mr. Fontana, 37, joined the Company in December
1992 as Director of Accounting Services. He held the position of Assistant
Controller from February 1994 through September 1994. Before joining the
Company, Mr. Fontana was a Senior Manager at the international accounting firm,
Ernst & Young LLP. He holds a bachelor of science degree in accounting from
Westchester State College and is a Certified Public Accountant.
Robert X. Kelleher: Vice President of Human Resources since
July 1986, Mr. Kelleher, 58, joined the Company in 1959 and has held various
managerial positions in the Finance, Accounting, Purchasing, Stores and
Employee Relations organizations. He was Industrial Relations Manager from
1975 to 1979, Manager of the Employee Relations Department from 1979 to 1985
and Assistant Vice President of the Employee Relations Department from 1985 to
1986. Mr. Kelleher is a graduate of St. Francis College and the Human
Resources Management and Executive Management Programs of Pennsylvania State
University. Mr. Kelleher is a member of the American Compensation Association,
Personnel Directors Council, Industrial Relations Research Institute, Edison
Electric Institute's Labor Relations Committee and is on the advisory council
of New York Institute of Technology's Center for Labor Relations.
John D. Leonard, Jr.: Mr. Leonard joined the Company in
1984, initially serving as Vice President of Nuclear Operations. He assumed
additional duties as Vice President of Corporate Services from July 1989
through March 1994. Mr. Leonard was named Vice President of Engineering and
Construction on April 1, 1994 and continues to be responsible for nuclear
issues. Mr. Leonard, 62, was the vice president and assistant chief engineer
for design and analysis at the New York Power Authority, from 1980 to 1984.
Prior to this position, he served as a resident manager of the Fitzpatrick
Nuclear Power Plant for approximately five years. Before accepting a position
at the New York Power Authority, Mr. Leonard served as corporate supervisor of
operational quality assurance of the Virginia Electric Power Company from 1974
to 1976. In 1974, Mr. Leonard retired with the rank of Commander from the
United States Navy, having commanded two nuclear powered submarines in a career
that spanned 20 years. He holds a bachelor of science degree from Duke
University and a master of science degree from the Naval Post Graduate School.
He is a Licensed Professional Engineer in the State of New York.
Adam M. Madsen: Vice President of Corporate Planning since
1984, Mr. Madsen, 58, holds a bachelors degree in electrical engineering from
Manhattan College and a master of science degree in nuclear engineering from
Long Island University. He has been with the Company since 1961, serving in
various engineering positions including Manager of Engineering from 1978 to
1984. Prior to that time, he held the position of Manager of the Planning
Department. Since 1978, Mr. Madsen has been the Company's representative to
the Planning Committee of the New York Power Pool. He is a member of the
Northeast Power Coordinating Council's Joint Coordinating Committee and an
alternate to the Council's Executive Committee. He also serves on the Board of
Directors of the Empire State Electric Energy Research Company. Mr. Madsen is
a Licensed Professional Engineer in the State of New York.
Kathleen A. Marion: Ms. Marion was named Vice President of
Corporate Services on April 1, 1994 and continues in her position of
Corporate Secretary which she assumed in April 1992. Ms. Marion has served as
Assistant to the Chairman since April 1987 and was Assistant Corporate
Secretary from April 1990 to 1992. Ms. Marion, 40, has a bachelor of science
degree in business and finance from the State University of New York at Old
Westbury.
Arthur C. Marquardt: Senior Vice President of Gas Business
Unit since March 1992, Mr. Marquardt, 48, joined the Company in January 1991.
He held the position of Vice President of Strategic Business Planning from
January 1991 through March 1992. He is chairman of the New York Facilities
executive committee, director of the Huntington Chamber of Commerce, the
Huntington Chamber Foundation, the Long Island Builders Institute and a member
of the Family Service League Business Advisory Council. Mr. Marquardt has had
extensive and varied business experience at Combustion Engineering Inc.,
General Electric Company, Quadrex Corporation, and at Pacific Nuclear Systems,
Inc. where he was president and chief operating officer. He received a
bachelor of science degree in mechanical engineering from Tufts University.
Brian R. McCaffrey: Vice President of Administration since
March 1987, Mr. McCaffrey, 49, joined the Company in 1973. Mr. McCaffrey holds
a bachelor of science degree in aerospace engineering from the University of
Notre Dame. He also received a master of science degree in aerospace
engineering from Pennsylvania State University and a master of science degree
in nuclear engineering from Polytechnic University. He is a Licensed
Professional Engineer in New York. Prior to this assignment as Vice President,
Mr. McCaffrey served in many positions in the nuclear organizations of the
Company and positions in engineering capacities associated with gas turbine and
fossil power station projects. Mr. McCaffrey is a member of the executive
board of the Suffolk County Council Boy Scouts of America.
Joseph W. McDonnell: Vice President of External Affairs since
July 1992, Dr. McDonnell, 43, joined the Company in 1984. Dr. McDonnell was
Assistant to the Chairman from 1984 through 1988 when he was named Vice
President of Communications. Prior to joining the Company, Dr. McDonnell was
the director of strategic planning and business administration for Applied
Digital Data Systems, Inc. and associate director of the University Hospital at
the State University of New York at Stony Brook. He holds bachelor of arts and
master of arts degrees in philosophy and a master of arts degree in theology
from the State University of New York at Stony Brook and a Ph.D in
communications from the University of Southern California.
Anthony Nozzolillo: Mr. Nozzolillo was named Senior Vice
President of Finance and Chief Financial Officer of the Company on February 4,
1994. His reporting responsibilities include the offices of Controller,
Treasurer, Tax & Benefits Planning, Investor Relations and Financial Planning.
Prior to this appointment he had been the Company's Treasurer since July 1992.
He has been with the Company since 1972 serving in various positions including
Manager of Financial Planning and Manager of Systems Planning. Mr. Nozzolillo
is a director of Nuclear Mutual Ltd. and was a director of Utilities Mutual
Insurance Company through December 1994. Mr. Nozzolillo, 46, holds a bachelor
of science degree in electrical engineering from the Polytechnic Institute of
Brooklyn and a master of business administration degree from Long Island
University C.W. Post Campus.
Richard Reichler: Mr. Reichler was named Deputy General
Counsel and Vice President of Tax and Benefit Compliance on December 14, 1994.
He held the position of Assistant Vice President for Tax and Benefits Planning
from October 1991 through December 1994. Prior to joining the Company, Mr.
Reichler, 60, was a partner in the international accounting firm, Ernst & Young
LLP for twenty-three years. He holds a bachelor of arts degree from Columbia
College and a bachelor of law degree from Columbia University School of Law.
Since 1989, he has taught various courses at Baruch College, including state
and local taxation, corporate taxation and real estate taxation. He has
authored several publications on tax and employee benefits topics and has
served as a member of the Executive Committee of the Tax Section of the New
York State Bar Association and as an advisor to the United Development
Corporation High Technology Advisory Council.
William G. Schiffmacher: Mr. Schiffmacher was named Vice
President of Customer Relations on April 1, 1994. He held the position of Vice
President of Electric Operations from July 1990 through March 1994. Mr.
Schiffmacher, 51, joined the Company in 1965 after receiving a bachelor of
electrical engineering degree from Manhattan College. Mr. Schiffmacher also
holds a master of science degree in management engineering from Long Island
University. He has held a variety of positions in the Company, including
Manager of Electric System Operation, Manager of Electrical Engineering and
Vice President of Engineering and Construction.
Robert B. Steger: Mr. Steger was named Vice President of
Electric Operations on April 1, 1994. He held the position of Vice President
of Fossil Production from February 1990 through March 1994. Mr. Steger, 58,
joined the Company in 1963 and has since held progressive operating and
engineering positions including Manager of Electric Production-Fossil from 1985
through 1989. He holds a bachelor of mechanical engineering degree from Pratt
Institute and is a Licensed Professional Engineer in the State of New York.
William E. Steiger, Jr.: Mr. Steiger was named Vice President
of Fossil Production on April 1, 1994. He held the position of Vice President
of Engineering and Construction from July 1990 through March 1994. Mr.
Steiger, 51, has been with the Company since 1968. During his career with the
Company, Mr. Steiger has served, among other positions, as Lead Nuclear
Engineer for Shoreham, Chief Operations Engineer for Shoreham, Plant Manager
for Shoreham as well as Assistant Vice President of Nuclear Operations. He
received a bachelor of science degree in marine engineering from the United
States Merchant Marine Academy and a master of science degree in nuclear
engineering from Long Island University.
Edward J. Youngling: Mr. Youngling was named Senior Vice
President of the Electric Business Unit on April 1, 1994. He held the position
of Vice President of Customer Relations and Conservation from March 1993
through March 1994. He joined the Company in 1968 as an Assistant Engineer in
the Electric Production Department and has held various positions in the
offices of fossil production, engineering and nuclear operations including
service as Department Manager of Nuclear Engineering. In 1988, Mr. Youngling
was named Vice President of Conservation and Load Management. In 1990, Mr.
Youngling became Vice President of Customer Relations. The Office of Customer
Relations and the Office of Conservation were merged in March 1994. Mr.
Youngling, 50, holds a bachelor of science degree in mechanical engineering
from Lehigh University.
CAPITAL REQUIREMENTS, LIQUIDITY AND CAPITAL PROVIDED:
Information as to Capital Requirements, Liquidity and Capital
Provided appears in Item 7, "Management's Discussion and Analysis of Financial
Condition and Results of Operations for the Year Ended December 31, 1994."
ITEM 2. PROPERTIES
The location and general character of the principal properties
of the Company are described in Item 1, "Business" under the headings "Electric
Operations" and "Gas Operations."
ITEM 3. LEGAL PROCEEDINGS
Shoreham
Pursuant to the Long Island Power Authority Act ("LIPA Act"),
LIPA is required to make PILOTS to the municipalities that impose real property
taxes on Shoreham. Pursuant to the 1989 Settlement, the Company agreed to fund
LIPA's PILOTS obligation. The timing and duration of PILOTS under the LIPA Act
are the subject of litigation entitled LIPA, et al. v. Shoreham-Wading River
Central School District, et al, brought in Nassau County Supreme Court by LIPA
against, among others, Suffolk County, the Town of Brookhaven and the
Shoreham-Wading River Central School District. The Company was permitted to
intervene in the lawsuit. On January 10, 1994, the Appellate Division, Second
Department, affirmed a lower court's March 29, 1993 decision holding, in major
part, that the Company is not obligated for any real property taxes that
accrued after February 28, 1992, attributable to property that it conveyed to
LIPA, that PILOTS commenced on March 1, 1992, that PILOTS are subject to
refunds and that the LIPA Act does not provide for the termination of PILOTS.
Generally, these holdings are favorable to the Company. On July 7, 1994, the
Court of Appeals denied a motion by all parties in which they sought leave to
appeal the Appellate Division decision on the basis that such decision is not a
final determination of this matter and therefore is not reviewable by the Court
of Appeals. The proper amount of PILOTS is to be determined in pending
litigation described in the next paragraph.
The costs of Shoreham included real property taxes imposed by
the Town of Brookhaven on Shoreham and capitalized by the Company during
construction. The Company has sought judicial review in Suffolk County Supreme
Court (Long Island Lighting Company v. The Assessor of the Town of Brookhaven,
et al.) of the assessments upon which those taxes were based for the years 1976
through 1992 (excluding 1979). The court has
consolidated the review of the tax years at issue into two phases: 1976
through 1983, excluding 1979 (Phase 1); and 1984 through 1992 (Phase 2). On
October 26, 1992, the court ruled that Shoreham had been overvalued for
property tax purposes for Phase 1. Although the court did not award a refund
because of a need to make further factual findings, the Company estimates that
it is entitled to a refund of approximately $34 million plus interest.
Regarding Phase 1, the Appellate Division, Second Department, affirmed the
Supreme Court's ruling and denied leave to appeal to the Court of Appeals. The
respondents have sought leave before the Court of Appeals to appeal to that
court. The Company has opposed this motion but has sought the Court of
Appeal's permission to appeal in the event that respondents' motion is granted.
In the Phase 2 proceeding, which is currently in progress, the Company is
seeking to recover over $500 million, excluding interest, in property taxes
paid on Shoreham during this period. The amount of the Company's recovery, if
any, in the Phase 2 proceeding and the timing of all refunds cannot yet be
determined. The Company has indicated to the PSC that all refunds, less
litigation costs, will be used to reduce future electric costs. LIPA has been
permitted to intervene for limited purposes in this pending litigation.
Environmental
On February 18, 1994, a lawsuit was filed in the United States
District Court for the Eastern District of New York by the Town of Oyster Bay
(the "Town"), against the Company and 19 other PRPs. The Town is seeking
indemnification for remediation and investigation costs that have been or will
be incurred for a federal Superfund site in Syosset, New York, which served as
a Town-owned and operated landfill between 1954 and 1975. In a Record of
Decision issued in September 1990, the EPA set forth a remedial design plan,
the cost of which was estimated at $27 million and is reflected in the Town's
lawsuit. In an Administrative Consent Decree entered into between the EPA and
the Town in December 1990, the Town agreed to undertake remediation at the
site. The Company has agreed to participate in a joint PRP defense effort with
several other defendants. Liability, if imposed, would be joint and several.
While the outcome of this matter is not certain, based upon the Company's past
experience in similar matters and the number and financial condition of the
corporate defendants named in the litigation, the Company does not believe that
this proceeding will have a material adverse effect on its financial condition.
Human Resources
Pending before federal and state courts, the Federal Equal
Employment Opportunity Commission and the New York State Division of Human
Rights are charges by individuals alleging that the Company discriminated
against them on various grounds.
The Civil Rights Bureau of the New York Attorney General's
office has subpoenaed the Company for the production of documents to aid in its
investigation as to whether the Company has engaged in discriminatory
employment practices based upon age. No charges have been filed by the
Attorney General.
The Company has estimated that any costs to the Company
resulting from these matters will not have a material adverse effect on its
financial condition.
Other Matters
On January 13, 1993, the New York State Department of Law
("DOL") informed the Company that the DOL's Antitrust Bureau opened an
investigation into its Full Service Pilot Program and Contractor Advisory
Council, two programs designed to increase the Company's residential natural
gas sales. The DOL stated that the implementation of the Full Service Pilot
Program and the practices of the Contractor Advisory Council may have
anticompetitive effects in the gas-fired heating equipment installation and
conversion business and that a preliminary investigation has raised questions
of possible violations of the New York General Business Law and the Sherman
Act. The DOL has not taken any further action in this matter. If required,
the Company expects that it can demonstrate that the programs identified by the
DOL for investigation are very limited in scope and do not involve
any violations. The outcome of the investigation by the DOL, if adverse, is
not expected to have a material effect on the financial condition of the
Company.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS
At March 1, 1995, the Company had 118,704,301 registered
holders of record of Common Stock.
The Common Stock of the Company is traded on the New York
Stock Exchange and the Pacific Stock Exchange. Certain of the Company's
Preferred Stock series are traded on the New York Stock Exchange.
Information respecting the high and low sales prices and the
dividends declared on the Company's Common Stock during the past two years is
set forth in the table below.
[Download Table]
1994 1993
-------------------------------- -------------------------------
Prices Dividends Prices Dividends
--------------- Declared Per ------------------ Declared Per
High Low Share High Low Share
----- ----- ---------- ------- ------- ---------
1st Quarter $24 1/4 $21 1/2 $0.445 $28 3/4 $24 7/8 $0.435
2nd Quarter 22 7/8 17 1/2 0.445 28 1/4 24 3/4 0.435
3rd Quarter 19 3/8 15 0.445 29 5/8 27 0.445
4th Quarter 18 1/8 15 1/4 0.445 27 3/4 23 1/4 0.445
Item 6: Selected Financial Data
[Enlarge/Download Table]
(In thousands of dollars except per share amounts)
--------------------------------------------------------------------------------------------------------------------------------
1994 1993 1992 1991 1990
--------------------------------------------------------------------------------------------------------------------------------
Summary of Operations Table 1
--------------------------------------------------------------------------------------------------------------------------------
Revenues $ 3,067,307 $ 2,880,995 $ 2,621,839 $ 2,547,729 $ 2,456,902
Operating expenses 2,322,362 2,125,444 1,880,734 1,762,449 1,654,272
--------------------------------------------------------------------------------------------------------------------------------
Operating income 744,945 755,551 741,105 785,280 802,630
Other income and (deductions) 52,719 70,874 66,330 40,482 20,638
--------------------------------------------------------------------------------------------------------------------------------
Income before interest charges and cumulative
effect of accounting change 797,664 826,425 807,435 825,762 823,268
Interest charges and (credits) 495,812 529,862 505,461 520,224 503,631
--------------------------------------------------------------------------------------------------------------------------------
Income before cumulative effect of
accounting change 301,852 296,563 301,974 305,538 319,637
--------------------------------------------------------------------------------------------------------------------------------
Cumulative effect of accounting change for
unbilled gas revenues (net of tax) - - - - 11,680
--------------------------------------------------------------------------------------------------------------------------------
Net income 301,852 296,563 301,974 305,538 331,317
Preferred stock dividend requirements 53,020 56,108 63,954 66,394 68,161
--------------------------------------------------------------------------------------------------------------------------------
Earnings for Common Stock $ 248,832 $ 240,455 $ 238,020 $ 239,144 $ 263,156
================================================================================================================================
Average common shares outstanding (000) 115,880 112,057 111,439 111,348 111,290
Earnings per common share
Before cumulative effect of accounting change $ 2.15 $ 2.15 $ 2.14 $ 2.15 $ 2.26
Cumulative effect of accounting change - - - - 0.10
--------------------------------------------------------------------------------------------------------------------------------
Earnings per Common Share $ 2.15 $ 2.15 $ 2.14 $ 2.15 $ 2.36
================================================================================================================================
Common stock dividends declared per share $ 1.78 $ 1.76 $ 1.72 $ 1.60 $ 1.25
Common stock dividends paid per share $ 1.78 $ 1.75 $ 1.71 $ 1.55 $ 1.125
Book value per common share at December 31 $ 20.21 $ 19.88 $ 19.58 $ 19.13 $ 18.57
Common shares outstanding
at December 31 (000) 118,417 112,332 111,600 111,365 111,324
Common shareowners of record at December 31 96,491 94,877 86,111 90,435 82,903
================================================================================================================================
--------------------------------------------------------------------------------------------------------------------------------
Capitalization Ratios* Table 2
--------------------------------------------------------------------------------------------------------------------------------
Long-term debt 62.5% 65.0% 64.7% 63.9% 62.2%
Preferred stock 8.6 8.5 8.8 8.8 9.4
Common equity 28.9 26.5 26.5 27.3 28.4
--------------------------------------------------------------------------------------------------------------------------------
Total 100.0% 100.0% 100.0% 100.0% 100.0%
================================================================================================================================
*Includes current maturities of long-term debt and current redemption
requirements of preferred stock.
[Enlarge/Download Table]
(In thousands of dollars)
------------------------------------------------------------------------------------------------------------------------------
Operations and Maintenance Expense Details Table 3
------------------------------------------------------------------------------------------------------------------------------
Payroll and employee benefits $ 436,611 $ 438,079 $ 413,817 $ 398,000 $ 357,689
Less - Charged to construction and other 103,974 116,988 124,076 123,838 97,650
------------------------------------------------------------------------------------------------------------------------------
Payroll and employee benefits charged to
operations 332,637 321,091 289,741 274,162 260,039
------------------------------------------------------------------------------------------------------------------------------
Fuel and Purchased Power
Fuel - electric operations 261,154 287,349 282,138 354,859 447,481
Fuel - gas operations 267,629 253,511 206,344 172,992 185,474
Purchased power costs 307,584 292,136 280,914 197,154 168,749
Fuel cost adjustments deferred 11,619 (5,405) (27,612) 43,697 (14,705)
------------------------------------------------------------------------------------------------------------------------------
Total fuel and purchased power 847,986 827,591 741,784 768,702 786,999
------------------------------------------------------------------------------------------------------------------------------
All other 208,017 200,569 208,204 248,597 215,770
------------------------------------------------------------------------------------------------------------------------------
Total Operations and Maintenance Expense $ 1,388,640 $ 1,349,251 $ 1,239,729 $ 1,291,461 $ 1,262,808
==============================================================================================================================
Full-time employees at December 31 5,947 6,215 6,438 6,538 6,545
------------------------------------------------------------------------------------------------------------------------------
[Enlarge/Download Table]
(In thousands of dollars)
------------------------------------------------------------------------------------------------------------------------
1994 1993 1992 1991 1990
------------------------------------------------------------------------------------------------------------------------
Electric Operating Income Table 4
------------------------------------------------------------------------------------------------------------------------
Revenues
------------------------------------------------------------------------------------------------------------------------
Residential $ 1,202,124 $ 1,145,891 $ 1,045,799 $ 1,047,490 $ 997,868
Commercial and industrial 1,196,422 1,132,487 1,076,302 1,070,098 1,017,387
Other system revenues 52,477 49,790 49,395 47,838 46,673
------------------------------------------------------------------------------------------------------------------------
Total system revenues 2,451,023 2,328,168 2,171,496 2,165,426 2,061,928
Sales to other utilities 14,895 12,872 9,997 23,040 24,140
Other revenues 15,719 11,069 13,139 8,102 9,592
------------------------------------------------------------------------------------------------------------------------
Total Revenues 2,481,637 2,352,109 2,194,632 2,196,568 2,095,660
------------------------------------------------------------------------------------------------------------------------
Operating Expenses
Operations - fuel and purchased power 568,738 579,032 559,583 593,656 611,122
Operations - other 310,438 306,116 294,909 296,798 271,608
Maintenance 107,573 111,765 105,341 127,446 118,545
Depreciation and amortization 111,996 106,149 104,034 104,172 98,022
Base financial component amortization 100,971 100,971 100,971 100,971 100,971
Rate moderation component amortization 197,656 88,667 (30,444) (228,572) (297,214)
Regulatory liability component amortization (79,359) (79,359) (79,359) (79,359) (79,359)
1989 Settlement credits amortization (9,214) (9,214) (9,214) (9,214) (9,214)
Regulatory amortization (4,883) (17,082) (21,984) 10,375 14,427
Operating taxes 336,263 326,407 331,122 338,429 322,197
Federal income tax - current 10,784 6,324 530 515 3,138
Federal income tax - deferred and other 156,646 158,941 158,908 173,259 169,274
------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 1,807,609 1,678,717 1,514,397 1,428,476 1,323,517
------------------------------------------------------------------------------------------------------------------------
Electric Operating Income $ 674,028 $ 673,392 $ 680,235 $ 768,092 $ 772,143
========================================================================================================================
[Enlarge/Download Table]
(In thousands of dollars)
------------------------------------------------------------------------------------------------------------------------
Gas Operating Income Table 5
------------------------------------------------------------------------------------------------------------------------
Revenues
Residential - space heating $ 326,474 $ 310,109 $ 243,950 $ 190,976 $ 198,734
- other 42,263 39,515 33,035 29,383 30,854
Commercial and industrial - space heating 126,092 106,140 90,363 70,938 68,441
- other 35,275 33,181 29,094 25,515 26,501
------------------------------------------------------------------------------------------------------------------------
Total firm revenues 530,104 488,945 396,442 316,812 324,530
Interruptible revenues 26,804 24,028 19,658 21,686 30,515
------------------------------------------------------------------------------------------------------------------------
Total system revenues 556,908 512,973 416,100 338,498 355,045
Other revenues 28,762 15,913 11,107 12,663 6,197
------------------------------------------------------------------------------------------------------------------------
Total Revenues 585,670 528,886 427,207 351,161 361,242
------------------------------------------------------------------------------------------------------------------------
Operating Expenses
Operations - fuel 279,248 248,559 182,201 175,046 175,877
Operations - other 95,576 81,692 77,300 78,469 68,910
Maintenance 27,067 22,087 20,395 20,046 16,746
Depreciation and amortization 18,668 16,322 15,103 14,783 12,862
Regulatory amortization 9,211 (962) (88) - -
Operating taxes 70,632 59,440 57,866 49,951 48,120
Federal income tax - current - - - - 500
Federal income tax - deferred and other 14,351 19,589 13,560 (4,322) 7,740
------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 514,753 446,727 366,337 333,973 330,755
------------------------------------------------------------------------------------------------------------------------
Gas Operating Income $ 70,917 $ 82,159 $ 60,870 $ 17,188 $ 30,487
========================================================================================================================
[Enlarge/Download Table]
-----------------------------------------------------------------------------------------------------------------
1994 1993 1992 1991 1990
-----------------------------------------------------------------------------------------------------------------
Electric Sales and Customers Table 6
-----------------------------------------------------------------------------------------------------------------
Sales - millions of kWh
Residential 7,159 7,118 6,788 7,022 7,022
Commercial and industrial 8,394 8,257 8,181 8,322 8,359
Other 457 449 471 469 472
-----------------------------------------------------------------------------------------------------------------
System sales 16,010 15,824 15,440 15,813 15,853
Sales to other utilities 372 304 227 598 532
-----------------------------------------------------------------------------------------------------------------
Total Sales 16,382 16,128 15,667 16,411 16,385
=================================================================================================================
CUSTOMERS - MONTHLY AVERAGE
Residential 908,490 905,997 902,885 898,974 895,294
Commercial and industrial 102,490 102,254 101,838 101,740 101,562
Other 4,583 4,553 4,593 4,540 4,504
-----------------------------------------------------------------------------------------------------------------
TOTAL CUSTOMERS - MONTHLY AVERAGE 1,015,563 1,012,804 1,009,316 1,005,254 1,001,360
=================================================================================================================
CUSTOMERS - AT DECEMBER 31 1,016,739 1,011,965 1,009,028 1,005,363 1,001,441
-----------------------------------------------------------------------------------------------------------------
RESIDENTIAL
kWh per customer 7,880 7,856 7,518 7,812 7,844
Revenue per kWh 16.79c. 16.10c. 15.41c. 14.92c. 14.21c.
-----------------------------------------------------------------------------------------------------------------
COMMERCIAL AND INDUSTRIAL
kWh per customer 81,902 80,749 80,346 81,797 82,304
Revenue per kWh 14.25c. 13.72c. 13.16c. 12.86c. 12.17c.
-----------------------------------------------------------------------------------------------------------------
SYSTEM
kWh per customer 15,765 15,624 15,297 15,731 15,832
Revenue per kWh 15.31c. 14.71c. 14.06c. 13.69c. 13.01c.
=================================================================================================================
-----------------------------------------------------------------------------------------------------------------
GAS SALES AND CUSTOMERS Table 7
-----------------------------------------------------------------------------------------------------------------
SALES - THOUSANDS OF DTH
Residential - space heating 35,693 37,191 35,089 29,687 29,810
- other 3,151 3,297 3,203 3,195 3,448
Commercial and industrial - space heating 15,679 14,366 13,662 11,636 11,271
- other 4,366 4,329 4,338 4,171 4,352
-----------------------------------------------------------------------------------------------------------------
Total firm sales 58,889 59,183 56,292 48,689 48,881
Interruptible sales 6,914 5,920 5,090 4,538 6,347
Off-system sales 7,232 2,894 - - -
-----------------------------------------------------------------------------------------------------------------
Total Sales 73,035 67,997 61,382 53,227 55,228
=================================================================================================================
CUSTOMERS - MONTHLY AVERAGE
Residential - space heating 239,857 233,882 227,834 220,562 211,400
- other 163,608 166,974 169,189 171,581 176,000
Commercial and industrial - space heating 33,776 32,783 31,666 30,453 29,072
- other 10,448 10,631 10,777 11,003 11,310
-----------------------------------------------------------------------------------------------------------------
Total firm customers 447,689 444,270 439,466 433,599 427,782
Interruptible customers 576 542 531 472 410
-----------------------------------------------------------------------------------------------------------------
TOTAL CUSTOMERS - MONTHLY AVERAGE 448,265 444,812 439,997 434,071 428,192
=================================================================================================================
CUSTOMERS - AT DECEMBER 31 449,906 446,384 442,117 436,853 430,571
-----------------------------------------------------------------------------------------------------------------
RESIDENTIAL
dth per customer 96.3 101.0 96.4 83.9 85.8
Revenue per dth $ 9.49 $ 8.64 $ 7.23 $ 6.70 $ 6.90
-----------------------------------------------------------------------------------------------------------------
COMMERCIAL AND INDUSTRIAL
dth per customer 453.3 430.6 424.1 381.3 386.9
Revenue per dth $ 8.05 $ 7.45 $ 6.64 $ 6.10 $ 6.08
-----------------------------------------------------------------------------------------------------------------
SYSTEM
dth per customer 146.8 146.4 139.5 122.6 128.9
Revenue per dth $ 8.46 $ 7.88 $ 6.78 $ 6.36 $ 6.43
-----------------------------------------------------------------------------------------------------------------
[Enlarge/Download Table]
1994 1993 1992 1991 1990
------------------------------------------------------------------------------------------------------------------
Electric Operations Table 8
------------------------------------------------------------------------------------------------------------------
Energy - millions of kWh
Net generation 10,034 10,514 10,592 13,570 13,981
Power purchased 7,640 7,023 6,438 4,236 3,521
------------------------------------------------------------------------------------------------------------------
Total Energy Available 17,674 17,537 17,030 17,806 17,502
==================================================================================================================
System sales 16,010 15,824 15,440 15,813 15,853
Company use and unaccounted for 1,292 1,409 1,363 1,395 1,117
------------------------------------------------------------------------------------------------------------------
Total system energy requirements 17,302 17,233 16,803 17,208 16,970
Sales to other utilities 372 304 227 598 532
------------------------------------------------------------------------------------------------------------------
Total Energy Available 17,674 17,537 17,030 17,806 17,502
==================================================================================================================
Peak Demand - MW
Station coincident demand 3,253 2,931 2,975 3,085 3,260
Power purchased - net 629 1,036 636 819 426
------------------------------------------------------------------------------------------------------------------
System Peak Demand 3,882 3,967 3,611 3,904 3,686
==================================================================================================================
System Capablility - MW
Company stations 4,063 4,063 4,091 4,078 4,077
Nine Mile Point 2 (18% share) 189 188 188 194 194
Firm purchases - net 616 548 432 423 408
------------------------------------------------------------------------------------------------------------------
Total Capability 4,868 4,799 4,711 4,695 4,679
==================================================================================================================
Fuel Consumed for Electric Operations
Oil - thousands of barrels 7,518 9,740 10,656 15,314 16,401
Gas - thousands of dth 44,308 36,269 34,475 32,924 36,477
Nuclear - thousands of MW days 183 181 124 154 108
Total - billions of Btu 91,669 98,025 102,126 129,937 139,874
Dollars per million Btu $2.69 $2.79 $2.62 $2.61 $3.07
Cents per kWh of net generation 2.88 c. 2.97 c. 2.76 c. 2.73 c. 3.24 c.
Heat rate - Btu per net kWh 10,740 10,628 10,558 10,484 10,564
------------------------------------------------------------------------------------------------------------------
Fuel Mix (Percentage of system requirements)
Oil 25 % 33 % 37 % 50 % 56 %
Gas 23 19 19 18 20
Purchased power 43 41 38 25 20
Nuclear fuel 9 7 6 7 4
------------------------------------------------------------------------------------------------------------------
Total 100 % 100 % 100 % 100 % 100 %
==================================================================================================================
------------------------------------------------------------------------------------------------------------------
Gas Operations Table 9
------------------------------------------------------------------------------------------------------------------
Energy - thousands of dth
Natural gas 75,360 69,970 64,911 55,579 55,407
Manufactured gas and change in storage 191 (68) 48 60 (15)
------------------------------------------------------------------------------------------------------------------
Total Company Requirements 75,551 69,902 64,959 55,639 55,392
==================================================================================================================
System Sales 65,803 65,103 61,382 53,227 55,228
Off-system sales 7,232 2,894 0 0 0
Company use and unaccounted for 2,516 1,905 3,577 2,412 164
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Total Company Requirements 75,551 69,902 64,959 55,639 55,392
==================================================================================================================
Maximum Day Sendout - dth 585,227 485,896 448,726 435,050 406,177
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System Capability - dth per day
Natural gas 579,897 561,584 561,584 507,344 507,344
LNG manufactured or LP gas 125,700 120,700 120,700 128,200 128,200
------------------------------------------------------------------------------------------------------------------
Total Capability 705,597 682,284 682,284 635,544 635,544
==================================================================================================================
Heating Degree Days
(30 year average 4,797) 4,839 4,899 5,066 4,378 4,139
------------------------------------------------------------------------------------------------------------------
[Enlarge/Download Table]
(In thousands of dollars)
--------------------------------------------------------------------------------------------------------------------------
1994 1993 1992 1991 1990
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Balance Sheet Table 10
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Assets
Net utility plant $ 3,498,346 $ 3,347,557 $ 3,161,148 $ 3,002,733 $ 2,888,079
Regulatory Assets
Base financial component 3,483,490 3,584,461 3,685,432 3,786,403 3,887,373
Rate moderation component 463,229 609,827 651,657 602,053 411,443
Shoreham post settlement costs 922,580 777,103 586,045 378,386 225,818
Shoreham nuclear fuel 73,371 75,497 77,629 79,760 92,069
Postretirement benefits other than pensions 412,727 402,921 - - -
Regulatory tax asset 1,831,689 1,848,998 - - -
Other 354,524 311,832 220,380 104,484 106,654
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Total regulatory assets 7,541,610 7,610,639 5,221,143 4,951,086 4,723,357
--------------------------------------------------------------------------------------------------------------------------
Nonutility property and other investments 24,043 23,029 20,730 9,788 6,381
Current assets 851,424 924,859 916,914 884,017 726,060
Deferred charges 1,301,257 1,487,032 1,444,524 1,290,871 1,173,361
--------------------------------------------------------------------------------------------------------------------------
Total Assets $ 13,216,680 $ 13,393,116 $ 10,764,459 $ 10,138,495 $ 9,517,238
==========================================================================================================================
Capitalization and Liabilities
Long-term debt $ 5,162,675 $ 4,887,733 $ 4,755,733 $ 5,001,016 $ 4,556,016
Unamortized discount on debt (17,278) (17,393) (14,731) (14,850) (23,125)
--------------------------------------------------------------------------------------------------------------------------
5,145,397 4,870,340 4,741,002 4,986,166 4,532,891
--------------------------------------------------------------------------------------------------------------------------
Preferred stock - redemption required 644,350 649,150 557,900 524,912 527,550
Preferred stock - no redemption required 63,957 64,038 154,276 154,371 154,674
--------------------------------------------------------------------------------------------------------------------------
Total preferred stock 708,307 713,188 712,176 679,283 682,224
--------------------------------------------------------------------------------------------------------------------------
Common stock 592,083 561,662 558,002 556,825 556,620
Premium on capital stock 1,101,240 1,010,283 998,089 993,509 992,885
Capital stock expense (52,175) (50,427) (39,304) (40,216) (42,676)
Retained earnings 752,480 711,432 667,988 620,373 560,405
--------------------------------------------------------------------------------------------------------------------------
Total common shareowners' equity 2,393,628 2,232,950 2,184,775 2,130,491 2,067,234
--------------------------------------------------------------------------------------------------------------------------
Total capitalization 8,247,332 7,816,478 7,637,953 7,795,940 7,282,349
--------------------------------------------------------------------------------------------------------------------------
Regulatory Liabilities
Regulatory liability component 357,117 436,476 515,835 595,194 674,554
1989 Settlement credits 145,868 155,081 164,294 173,507 182,720
Regulatory tax liability 111,218 114,748 - - -
Other 143,611 138,612 100,470 72,277 102,655
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Total regulatory liabilities 757,814 844,917 780,599 840,978 959,929
--------------------------------------------------------------------------------------------------------------------------
Current liabilities 605,478 1,188,972 1,181,297 492,895 449,830
Deferred credits 3,102,434 3,109,593 1,147,310 1,001,375 816,790
Operating reserves 503,622 433,156 17,300 7,307 8,340
--------------------------------------------------------------------------------------------------------------------------
Total Capitalization and Liabilities $ 13,216,680 $ 13,393,116 $ 10,764,459 $ 10,138,495 $ 9,517,238
==========================================================================================================================
(In thousands of dollars)
--------------------------------------------------------------------------------------------------------------------------
Construction Expenditures* Table 11
--------------------------------------------------------------------------------------------------------------------------
Electric $ 136,041 $ 137,583 $ 141,752 $ 129,643 $ 141,028
Gas 120,019 124,859 104,028 89,950 78,766
Common 23,610 42,251 27,124 17,958 12,671
--------------------------------------------------------------------------------------------------------------------------
Total Construction Expenditures $ 279,670 $ 304,693 $ 272,904 $ 237,551 $ 232,465
==========================================================================================================================
*Includes non-cash allowance for other funds used during construction and
excludes Shoreham post settlement costs.
ITEM 7: MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
This discussion and analysis addresses matters of significance with regard to
the Company and its financial condition, liquidity, capital requirements and
results of operations for the last three years.
OVERVIEW
In 1994, the Company reached a milestone by generating sufficient cash from
operations to meet all of its operating and construction requirements in
addition to satisfying a portion of its maturing debt obligations with cash on
hand. The positive cash flow resulted, in part, from the collection of
deferred revenues associated with the Rate Moderation Component (RMC) and the
Long Island Lighting Company Ratemaking and Performance Plan, and the Company's
continued efforts to maximize operating efficiencies while reducing operating
costs.
Since 1989, the Company has received six electric rate increases and has
experienced lower than anticipated fuel costs, financing costs and production
expenses, all of which have helped to improve cash flow, which in turn, has
improved the Company's financial health. This improved financial health has
enabled the Company to file with the Public Service Commission of the State of
New York (PSC) on December 31, 1993, a three year electric rate plan (Electric
Rate Plan) requesting that base electric rates be frozen through November 30,
1996, and that overall electric rates increase 4.3% beginning December 1, 1996.
The Electric Rate Plan, as designed, will help to better position the Company
to meet existing and anticipated competitive challenges in addition to
assisting the economic recovery of Long Island.
Three Administrative Law Judges (ALJs) issued a recommended decision to the PSC
with respect to the Company's Electric Rate Plan. The ALJs agreed with the
Company's proposal to freeze base electric rates for the first year, and
implied that base rates could remain frozen for the second year as well. The
ALJs encouraged the Company and other intervening parties in the proceeding to
negotiate a settlement regarding the third year of the Company's Electric Rate
Plan. The Company, the PSC and other parties to this proceeding continue to
negotiate toward a three year rate settlement. The Company believes that a
three year rate settlement is in the best interest of shareowners and
ratepayers.
Other significant achievements during 1994 included:
- The Company maintained the same level of earnings per common share in
1994 as in 1993, despite a lower allowed return on common equity for
the gas business and the issuance of 6.1
million shares of common stock during 1994;
- The public offering of 5.1 million shares of the Company's common
stock, for the first time in nearly ten years, raised approximately
$100 million. This offering, combined with the satisfaction of a
portion of maturing debt with cash on hand, has resulted in a
reduction of the Company's debt ratio to 62.5% at December 31, 1994
from 65.0% at December 31, 1993;
- The continuation of the Company's quarterly common stock dividend rate
at 44 1/2 cents per share;
- The reduction of the Company's average coupon rate on its outstanding
long-term debt to 7.9% as a result of the Company's refinancing
activities. The refinancing of a significant amount of the Company's
long-term debt and preferred stock, over the past several years, has
resulted in annual cash savings of approximately $100 million;
- The reduction of the RMC balance from $610 million at December 31,
1993 to $463 million at December 31, 1994. This reduction resulted,
in part, from current year revenues under the Rate Moderation
Agreement exceeding revenues that were required in 1994 under
conventional ratemaking;
- The completion, pending final regulatory approval, of the
decommissioning of the Shoreham Nuclear Power Station, including the
removal and transportation of Shoreham's fuel to another utility;
- The receipt of a gas rate increase effective December 1, 1994, which
is the second of three gas rate increases under a three-year
settlement between the Company and the PSC which provides for annual
rate increases of 4.7%, 3.8% and 2.8% for the rate years beginning
December 1, 1993, 1994 and 1995, respectively;
- The addition of over 8,500 new gas space heating customers, resulting
from the continuation of the Company's gas expansion program;
- The establishment of a record maximum day gas sendout of 585,227
dekatherms on January 19, 1994.
In addition, in 1994, the Company received an invitation at the request of the
former Governor of New York State (State), from the chief executives of the New
York Power Authority and the Long Island Power Authority, for the Company to
enter into negotiations with them in a proposal to convert the Company into a
public power utility. The new Governor of the State empaneled
a task force to study the "takeover" proposal. While the task force did not
make its recommendation public, published reports in local newspapers indicate
that the task force recommended to reject the proposal.
LIQUIDITY
At December 31, 1994, the Company's cash and cash equivalents amounted to
approximately $185 million, compared to $249 million at December 31, 1993. The
decrease in cash and cash equivalents reflects the Company's strategy of
applying available cash balances toward the satisfaction of maturing debt.
The Company has available for its use a $300 million revolving line of credit
through October 1, 1995, provided by its 1989 Revolving Credit Agreement (1989
RCA). At December 31, 1994, no amounts were outstanding under the 1989 RCA.
This line of credit is secured by a first lien upon the Company's accounts
receivable and fuel oil inventories. The 1989 RCA may be extended for one year
periods upon the acceptance by the lending banks of a request by the Company.
The Company's request must be delivered to the lending banks prior to April 1
of each year. In 1995, the Company intends to request such an extension. For
a further discussion of the 1989 RCA, see Note 7 of Notes to Financial
Statements.
CAPITALIZATION
The Company's capitalization, including current maturities of long-term debt
and current redemption requirements of preferred stock, at December 31, 1994,
was approximately $8.3 billion, compared to $8.4 billion at December 31, 1993.
At December 31, 1994 and 1993, the Company's capitalization ratios were as
follows:
[Download Table]
1994 1993
------ ------
Long-term debt 62.5% 65.0%
Preferred stock 8.6 8.5
Common shareowners' equity 28.9 26.5
------ ------
100.0% 100.0%
====== ======
The Company is committed to reducing its debt ratio. To achieve this goal, the
Company intends to continue reducing debt with cash generated from operations
and intends to issue common or preferred stock if market conditions prove
favorable. With this commitment in mind, the Company issued 5.1 million shares
of common stock in 1994, marking the first time in approximately ten years that
the Company issued common equity, other than through its Automatic Dividend
Reinvestment Plan, its Employee Stock Purchase Plan or through the conversion
of Series I Preferred Stock.
In 1994, the Company applied the net proceeds from the sale of the 5.1 million
shares of common stock and the issuance of $285 million of General and
Refunding Bonds (G&R Bonds) toward the repayment, at maturity, of $400 million
of debentures and the redemption of $30 million and $5 million of debentures
that had
been scheduled to mature in 1999 and 2019, respectively. Cash from operations
provided the balance of funds needed to retire/redeem this debt and to retire
$25 million of First Mortgage Bonds, which matured in June 1994. In addition,
in November 1994 the Company used cash on hand to satisfy the payment of $175
million of maturing debentures.
The Company's need to access the financial markets to provide additional
capital or to refinance its maturing debt has diminished compared to prior
years. The Company intends to use cash generated from operations to satisfy
the payment of $25 million of First Mortgage Bonds maturing on June 1, 1995.
With respect to the repayment of $455 million and $286 million of debt maturing
in 1996 and 1997, respectively, the Company intends to use cash generated from
operations to the maximum extent practicable. The balance of funds necessary
to satisfy maturing debt obligations in 1996 and 1997 will be obtained through
the issuance of either debt or equity securities, or some combination thereof.
Despite improving financial indicia, the Company's securities, which are rated
by Standard and Poor's Corporation (S&P), Moody's Investors Service (Moody's),
Fitch Investors Service, L.P. (Fitch) and Duff and Phelps, Inc. (D&P), have
been downgraded by certain rating agencies over the past eighteen months. In
June 1994, Moody's lowered the credit ratings of the Company reflecting Moody's
expectations that the Company's high tariff rates will intensify business risk
in an increasingly competitive environment. Recently, S&P placed its ratings on
the Company's securities on "Credit Watch with negative implications," Fitch
changed its credit trends to "declining" and Moody's placed the Company's
credit ratings under review for a possible downgrade reflecting their
respective concerns about the regulatory environment in New York State.
At December 31, 1994, the ratings for each of the Company's principal
securities were as follows:
[Download Table]
S&P Moody's Fitch D&P
--- ------- ----- ---
. First Mortgage
Bonds BBB- Baa3 BBB BBB
. G&R Bonds BBB- Baa3 BBB BBB
. Debentures BB+ Ba1 BBB- BB+
. Preferred Stock BB+ ba1 BBB- BB
. Minimum Investment
Grade BBB- Baa3 BBB- BBB-
Bold face indicates securities that meet or exceed minimum investment
grade.
The Company's Authority Financing Notes (Notes), some of which are secured by
letters of credit, are rated by certain of the rating agencies. The ratings on
the Notes secured by letters of credit reflect the ratings of the institutions
issuing the letters of credit, and not that of the Company.
CAPITAL REQUIREMENTS AND CAPITAL PROVIDED
Capital requirements and capital provided for 1994 and 1993 were as follows:
[Download Table]
Capital Requirements 1994 1993
-------------------- ------- -------
(In millions of dollars)
Construction
Electric $ 135 $ 136
Gas 119 125
Common 23 41
-------- -------
Total Construction 277 302
Refundings and Dividends
Long-term debt 635 960
Preferred stock 5 206
Common stock dividends 205 196
Preferred stock dividends 53 57
Redemption costs 2 15
-------- -------
Total Refundings and Dividends 900 1,434
Shoreham post settlement costs 167 207
-------- -------
Total Capital Requirements $ 1,344 $ 1,943
======== =======
Capital Provided
----------------
Cash generated from operations $ 836 $ 582
Long-term debt issued 331 1,090
Common stock issued 118 14
Preferred stock issued - 202
Financing costs (4) (6)
Decrease in cash 63 61
------- ------
Total Capital Provided $ 1,344 $ 1,943
======== =======
For further information, see the Statement of Cash Flows.
Given the Company's current electric load forecast and the availability of
electricity provided by the Company's generating facilities and by purchases of
power from others, the Company forecasts that it will not need any new
generating facilities until beyond the year 2000. As a result, the Company
does not forecast any need for external financing for the construction of
generating facilities during this period. With respect to financing other
capital additions to plant, the Company estimates that cash generated from
operations will be sufficient to meet any such requirements in 1995.
For 1995, total capital requirements (excluding common stock dividends) are
estimated at $431 million, of which maturing debt is $25 million, additions to
plant are $277 million, preferred stock dividends are $53 million, preferred
stock sinking funds are $5 million and Shoreham post settlement costs are $71
million, including $58 million for payments in lieu of taxes.
RATE MATTERS
Electric
In conjunction with the 1989 Settlement, the PSC agreed to the recognition of a
regulatory asset known as the Financial Resource Asset (FRA). The FRA consists
of two components, the Base Financial Component (BFC) and the RMC, discussed in
Note 1 of Notes to Financial Statements. The Rate Moderation Agreement (RMA),
one of the constituent documents of the 1989 Settlement, provides for the full
recovery of the FRA.
The BFC was granted rate base treatment under the terms of the RMA and is
included in the Company's revenue requirements through an amortization included
in rates over forty years on a straight-line basis that began July 1, 1989.
The RMC had provided the Company with a substantial amount of non-cash earnings
since the effective date of the 1989 Settlement through December 31, 1992, as
the revenues provided under the RMA were less than the revenues required under
conventional ratemaking. During 1993, however, as revenues provided under the
RMA began to exceed the revenues that would have been provided under
conventional ratemaking, the RMC balance began to decline.
Pursuant to the 1989 Settlement, the Company has received six electric rate
increases as contemplated by the RMA. In November 1991, the PSC approved the
Long Island Lighting Company Ratemaking and Performance Plan (LRPP) which
provided annual electric rate increases of 4.15%, 4.1% and 4.0% effective
December 1, 1991, 1992 and 1993, respectively. The LRPP provided for an
allowed return on common equity from electric operations of 11.6% for each of
the three rate years.
The LRPP was designed to be consistent with the RMA's long-term goals. One
principal objective of the LRPP is to reassign risk so that the Company assumes
the responsibility for risks within the control of management, whereas risks
largely beyond the control of management would be assumed by the ratepayers.
One of the major components of the LRPP provides for a revenue reconciliation
mechanism that eliminates the impact on earnings of experiencing electric sales
that are above or below the LRPP forecast by providing a fixed annual net
margin level (defined as sales revenues, net of fuel and gross receipts taxes)
that the Company receives under the LRPP.
The LRPP allows the Company to earn for each rate year up to 60 additional
basis points, or forfeit up to 38 basis points, of the allowed return on common
equity as a result of the Company's performance within certain incentive and/or
penalty programs. These programs consist of a customer service performance
plan, a demand side management (DSM) program, a time-of-use program, a partial
pass through fuel cost incentive plan, and effective December 1, 1993, an
electric transmission and distribution reliability plan. Based upon the
Company's performance within these programs, the Company earned a total of 50
and 49 basis points, or approximately $9.2 million, net of tax effects, for
each of the rate years ended November 30, 1994, and 1993. For the rate year
ended November 30, 1992, the Company earned approximately $4.3 million, net of
tax effects, for its performance in these programs.
The LRPP contains a mechanism whereby earnings in excess of the allowed return
on common equity of 11.6%, excluding the impacts of the various incentive
and/or penalty programs, are shared equally between ratepayers and shareowners.
The Company earned $8.9 million and $21.4 million, net of tax effects, for the
rate years ended November 30, 1993 and 1992, respectively, in excess of its
allowed return on common equity which was shared equally between ratepayers (by
a reduction to the RMC) and shareowners. For the rate year ended November 30,
1994, the Company did not earn in excess of its allowed return on common
equity.
In December 1993, the Company filed a three year Electric Rate Plan with the
PSC for the period beginning December 1, 1994 that minimizes future electric
rate increases while retaining consistency with the RMA's objective of the
restoration of the Company's financial health. The Electric Rate Plan requests
an allowed return on common equity of 11.0%, and provides for base rates to be
frozen in years one and two and an overall rate increase of 4.3% in the third
year. Although base electric rates would be frozen during the first two years
of the Electric Rate Plan, annual rate increases of approximately 1% are
expected to result from the operation of the Company's fuel cost adjustment
(FCA) clause. The FCA captures, among other things, amounts to be recovered
from or refunded to ratepayers in excess of $15 million, which result from the
reconciliation of revenues, certain expenses and earned performance incentive
components, under the LRPP, discussed in Note 3 of Notes to Financial
Statements.
The Company's Electric Rate Plan reflects four underlying objectives: (i) to
limit the balance of the RMC during the three year period to no more than its
1992 peak balance of $652 million; (ii) to recover the RMC within the time
frame established in the 1989 Settlement; (iii) to minimize, beginning in the
third year of the Electric Rate Plan, the final three rate increases
contemplated in the 1989 Settlement that follow the two
year rate freeze period; and (iv) to continue the Company's gradual return to
financial health.
The Electric Rate Plan provides for, with some modifications, the continuation
of the LRPP revenue and expense reconciliations and performance incentives.
The Electric Rate Plan includes the annual reconciliation of certain expenses
for property taxes, interest costs, DSM costs and the deferral and amortization
of certain costs for enhanced reliability. The Company would be allowed to
earn for each of the three rate years under the Electric Rate Plan up to 50
additional basis points, excluding incentives under the DSM program, or forfeit
up to 47 basis points of the allowed return on common equity of 11.0% as a
result of the Company's performance within certain performance programs. These
programs consist of a customer service program, a partial pass through fuel
cost incentive plan, a DSM program and an electric transmission and
distribution reliability plan.
The Company's Electric Rate Plan provides for lower annual electric rate
increases than originally anticipated under the 1989 Settlement. However, as a
result of changes in certain assumptions upon which the RMA was based, their
impact on the RMC and the Company's plans to reduce DSM, operations and
maintenance and capital expenditures, the Company has determined that the
overall objectives of the RMA can be met under the Electric Rate Plan. As a
result of lower than originally anticipated inflation, interest costs, property
taxes, fuel costs and return on common equity allowed by the PSC, the RMC,
which originally had been anticipated to peak at $1.2 billion in 1994, peaked
at $652 million in 1992. With the exception of a projected increase in 1995
and 1996, which is not now anticipated to cause the RMC to increase above its
$652 million peak, the RMC is expected to decline until it is fully amortized.
Under the Electric Rate Plan, the recovery of the RMC would be extended, if
necessary, for an additional period of not more than three years beyond the
approximate ten year period envisioned in the RMA. The actual length of the
RMC extension will depend upon the extent to which the assumptions underlying
the Electric Rate Plan materialize. The Company's current projections indicate
that the RMC will be recovered in eleven years.
The Staff of the PSC (Staff) and other intervening parties filed testimony in
response to the Company's Electric Rate Plan. Staff concurs with the Company's
proposal for an 11.0% return on common equity in each of the three years, and
has reaffirmed its commitment to the principals of the RMA, including the full
recovery of the RMC within the time frame established by the RMA. However,
Staff has recommended an overall zero percent rate increase for the first two
years, contrasted with the Company's proposal for a base rate freeze with FCA
adjustments of approximately 1% in years one and two, as described above.
Staff
did not make a recommendation for the level of rate relief in the third year.
In September 1994, three ALJs of the PSC issued a recommended decision to the
PSC with respect to the Company's Electric Rate Plan. The ALJs agreed with the
Company's proposed 11.0% return on common equity and its proposal to freeze
base electric rates for the first rate year. While no explicit recommendation
was made concerning the second year, the recommended decision implied that base
rates could remain frozen for the second rate year as well.
With respect to the third rate year beginning December 1, 1996, the ALJs
determined that it was not appropriate for them to issue a recommendation
since, in their opinion, the Company's revenue requirements for the third rate
year could not be precisely determined at this time. Alternatively, the ALJs
encouraged the Company and other parties in the proceeding to negotiate a
settlement concerning any rate increase for the third rate year.
The PSC had been expected to issue a final order on the Company's Electric Rate
Plan before November 29, 1994, the date that the statutory suspension period
was scheduled to terminate. However, in order to accommodate further
settlement negotiations in the proceeding, the Company has requested extensions
through April 1995, which were granted by the PSC. The Company's offers to
extend the suspension period were conditioned upon the continuation of the
current LRPP rate mechanisms. Although the ultimate outcome of the Electric
Rate Plan cannot be predicted, the Company expects that any PSC order will be
consistent with the provisions of the RMA respecting the recovery of the FRA
and other 1989 Settlement deferred charges.
Gas
In December 1993, the PSC approved a three year gas rate settlement, between
the Company and the Staff of the PSC. The gas rate settlement provides that
the Company receive, for each of the rate years beginning December 1, 1993,
1994 and 1995, annual gas rate increases of 4.7%, 3.8% and 2.8%, respectively.
In the determination of the revenue requirements for the gas rate settlement,
an allowed return on common equity of 10.1% was used. The gas rate decision
provides that earnings in excess of a 10.6% return on common equity in any of
the three rate years covered by the settlement be shared equally between the
Company's firm gas customers and its shareowners. For the rate year ended
November 30, 1994, the Company earned $9.2 million, net of tax effects, in
excess of the 10.6% return on common equity. The firm gas customers' portion
of these excess earnings amounting to $4.6 million, net of tax effects, has
been deferred until its final disposition is determined by the PSC.
ENVIRONMENT
During 1994, the Company spent approximately $6.4 million in order to comply
with the 1990 amendments to the Federal Clean Air Act (Act). These
expenditures were necessary to meet continuous emissions monitoring
requirements and Phase I nitrogen oxide (Nox) reduction requirements under the
Act.
The Company expects that it will have to expend approximately $1 million in
1995 to meet continuous emission monitoring requirements and to meet Phase I
Nox reduction requirements. In order to generate 210 tons of NOx reduction
credits already under contract for sale to a third party, the Company
anticipates spending $2.5 million in 1995 and $1.9 million in 1996 for earlier
than required Nox reduction systems. Subject to requirements that are expected
to be promulgated in forthcoming regulations, the Company estimates that it may
be required to spend an additional $80 million (net of Nox credit sales) by
2003 to meet Phase II and Phase III NOx reduction requirements. In an effort
to minimize costs associated with anticipated NOx reduction requirements, the
Company is engaged in a $7 million research and development project along with
several co-funding organizations to demonstrate an innovative NOx reduction
technology at its E.F. Barrett Power Station. The Company is committed to
fund $3.6 million of the project costs. Through 1994, approximately $5 million
has been expended by all of the co-funders. It is anticipated that the
remaining $2 million will be spent in 1995. In addition, the Company estimates
that it may be required to spend approximately $24 million by 1999 to meet
potential requirements for the control of hazardous air pollutants from power
plants. The Company believes that all of the above mentioned costs will be
recoverable through rates.
The New York State Department of Environmental Conservation has indicated to
New York State utilities that it may require all such utilities to investigate
and, where necessary, remediate their former manufactured gas plant (MGP)
sites. The Company is the owner of six pieces of property on which the Company
or certain of its predecessor companies produced manufactured gas. Although
the exact amount of the Company's clean-up costs cannot yet be determined,
based on the findings of investigations at two of these six sites, preliminary
estimates indicate that it will cost approximately $35 million to clean-up all
of these sites over the next five to ten years. Accordingly, the Company has
recorded a $35 million liability and a corresponding regulatory asset to
reflect its belief that the PSC will provide for the future recovery of these
costs through rates as it has for other New York State utilities. The Company
has notified its former and current insurance carriers that it seeks to recover
from them certain of these clean-up costs. However, the Company is unable to
predict the amount of insurance recovery, if any, that it may obtain.
The Company has been notified by the Environmental Protection Agency (EPA) that
it is one of many potentially responsible parties (PRPs) that may be liable for
the remediation of three contaminated licensed treatment, storage and disposal
sites. At one site, located in Philadelphia, Pennsylvania, and operated by
Metal Bank of America, the Company and nine other PRPs, all of which are public
utilities, have completed a Remedial Investigation and Feasibility Study which
is currently being reviewed by the EPA. The level of remediation required will
be determined when the EPA issues its decision, currently expected in May 1995.
The Company currently anticipates that the total cost to remediate this site
will be between $14 million and $30 million. The Company has recorded a
liability of $1.1 million representing its estimated share of the cost to
remediate this site. The Company believes that any cost incurred to remediate
this site will be recoverable through rates.
With respect to the other two sites, which are located in Kansas City, Kansas
and Kansas City, Missouri, the Company is investigating allegations that it had
previously stored or made agreements for the disposal of polychlorinated
biphenyls (PCBs) or items containing PCBs at these sites. The Company is
currently unable to determine its share of the cost to remediate these sites or
the impact, if any, on the Company's financial position. The Company believes
that any cost incurred to remediate these sites will be recoverable through
rates.
NYPA AND LIPA PROPOSAL
At the request of the then Governor of the State of New York, on October 13,
1994 the chief executives of the New York Power Authority (NYPA) and the Long
Island Power Authority (LIPA) invited the Company to enter into negotiations
with them regarding a proposal to convert the Company into a public power
utility. Under the proposal, the two state authorities contemplated a
business combination in which holders of the Company's common stock would
receive $21.50 in cash for each outstanding share of the Company's common
stock. NYPA and LIPA indicated that the completion of this transaction would
be subject to, among other things, the availability of tax-exempt financing
sufficient to complete the transaction and the verification by NYPA and LIPA
that the transaction would result in rate reductions in excess of 10%. The
Company's Board of Directors has authorized the Company to enter into
discussions with NYPA and LIPA to explore the proposal in greater detail, but
no such discussions have been held.
The new Governor of the State of New York had empaneled a task force
to study the takeover proposal. While the task force did not make its
recommendation public, published reports in local newspapers indicate that the
task force recommended to reject the proposal.
COMPETITIVE ENVIRONMENT
Significant changes are taking place in the business and regulatory environment
in which electric utilities operate. In response, the Company, like utilities
across the nation, is actively involved with federal and State agencies in
evaluating what type of competition would best serve both customers and
investors. The Company has also undertaken a review of its current operations,
seeking to shape those operations to best meet the challenges of a competitive
environment. As federal legislators and regulators continue pursuing a policy
of evaluating competition in the electric utility industry, state regulators
are addressing the many complex and politically sensitive issues which will
affect the cost and reliability of service to customers in their jurisdictions.
The focus on electric competition has also prompted municipalities, school
districts and certain other customers to seek permission to buy energy
elsewhere.
The Electric Industry - Federal Regulatory Issues
As a result of Congress' passage of the Public Utility Regulatory Policies Act
of 1978 (PURPA) and the National Energy Policy Act of 1992 (NEPA), the once
monopolistic electric utility industry now faces competition.
PURPA's goal was to reduce the United States' dependence on foreign oil,
encourage energy conservation and promote diversification of fuel supply.
Accordingly, PURPA provided for the development of a new class of electric
generators which rely on either cogeneration technology or alternate fuels.
The utilities are obligated under PURPA to purchase the electric output of
certain of these new generators, which are known as qualified facilities (QFs).
NEPA sought to increase economic efficiency in the creation and distribution of
power by relaxing restrictions on the entry of new competitors to the wholesale
electric power market (i.e., sales to an entity for resale to the ultimate
consumer). NEPA does so by creating exempt wholesale generators that can sell
power in wholesale markets without the regulatory constraints placed on
generators such as the Company. NEPA also expanded the Federal Energy
Regulatory Commission (FERC)'s authority to grant access to utility
transmission systems to all parties who seek wholesale wheeling for wholesale
competition. Significant issues associated with the removal of wholesale
transmission system access restrictions have yet to be resolved and the
potential impact on the Company's financial position cannot yet be determined.
FERC is in the process of setting policy which will largely
determine how wholesale competition will be implemented. FERC has recently
declared that utilities must provide wholesale wheeling to others that is
comparable to the service utilities provide themselves. The policy will be
tested and further defined in individual proceedings. In addition, FERC has
issued policy statements concerning regional transmission groups, transmission
information requirements and "good faith" requests for service and transmission
pricing. FERC is also initiating proceedings to address issues relating to
stranded assets and power pooling. Utilities, including the Company, and other
interested parties are actively involved in these proceedings.
Major issues are arising as the industry and government contemplate the move
toward a more market-driven environment. These issues include: the impact of
competition on customers who are unable to or who have chosen not to avail
themselves of competition options; the ability of utility investors to continue
to receive a return of and a reasonable return on their investments; the effect
on service quality and reliability; comparability of service; the parameters of
regulatory jurisdiction; the relative efficiency of competitors; the effects of
mergers and the recoverability of transition costs and of assets that may
become impaired.
The Electric Industry - New York State Regulatory Issues
The PSC has instituted a number of cases which will determine the boundaries
within which power providers can compete in New York.
In 1994, the PSC completed the first phase of a competitive opportunities
proceeding, issuing guidelines that allow New York utilities, at their option,
to negotiate discounted rates with customers who otherwise would purchase
electricity elsewhere. Any net revenue lost through these negotiations will be
shared between ratepayers and shareowners, with percentages to be determined in
rate cases. With respect to the Company, the Commission has ruled that the
Company's shareowners must bear 30% of any "discount" negotiated by the Company
in order to retain customers. While this percentage is comparable to that
required of other utilities, the Company believes the percentage should be
significantly lower due to the Company's unique financial structure and,
therefore, has appealed the PSC's decision.
The PSC has recently begun a second phase of this proceeding in which it will
develop principles to guide the transition to a more competitive environment,
explore how to improve the wholesale electric market and determine the role
regulation will play. The issues to be reviewed include: wholesale
competition with or without a spin-off of generation assets; retail
competition; planning and reliability; customer impacts; financial and legal
considerations; and affordability of electric
service to all customers. The PSC will also address the critical issue of
whether utilities will be required to write- off assets in order to offer more
competitive prices.
In addition, the State Energy Planning Board has released the 1994 State Energy
Plan (SEP) which calls for the development of a fully competitive wholesale
generation market within five years. While continuing to caution that full
retail competition may not be in the best interests of the State, the SEP
threatens that retail competition should be considered sooner "in the absence
of utility cooperation" in the development of a fully competitive wholesale
market.
The Company's Service Territory
The changing utility regulatory environment has affected the Company in a
number of ways. For example, PURPA's encouragement of the non-utility
generator (NUG) industry has negatively impacted the Company. The Company
estimates that in 1994, sales lost to NUGs totaled 237 gigawatt-hours (Gwh)
representing a loss in revenues net of fuel (net revenues) of approximately $24
million, or approximately 1.1% of the Company's 1994 net revenues.
Additionally, as mentioned above, the Company is required to purchase all the
power offered by QFs. As of December 31, 1994, QFs were selling approximately
203 megawatts (MW) of power to the Company. The Company estimates that, in
1994, purchases from QFs required by federal and State law cost the Company $53
million more than it would have cost had the Company generated this power. The
Company has also contracted, beginning in early 1995, to purchase all excess
power from the 40 MW Stony Brook project located at the State University of New
York at Stony Brook, New York.
QFs have the choice of pricing sales to the Company at either (i) the PSC's
published estimates of the Company's long run avoided costs (LRAC) or (ii) the
Company's tariff rates, which are modified from time to time, reflecting the
Company's actual avoided costs. Additionally, until repealed in 1992, New York
State law set a minimum price of six cents per kilowatt-hour (kWh) for utility
purchases of power from certain categories of QFs, considerably above the
Company's avoided cost. The six cent minimum now only applies to contracts
entered into before June 1992. The Company believes that the repeal of the six
cent law, coupled with recent PSC updates which resulted in lower LRAC
estimates, has significantly reduced the economic benefits to QFs seeking to
sell power to the Company.
After the anticipated loss of the Stony Brook load, estimated to be
approximately 190 Gwhs annually, or a net revenue loss of
approximately $13 million, the Company expects that electric load losses due to
NUGs will stabilize. The Company believes that a number of factors, including
customer load characteristics such as a lack of a significant industrial base
and related large thermal load, will mitigate load loss and thereby make
cogeneration economically unattractive.
The Company has also experienced a revenue loss as a result of its policy of
voluntarily providing wheeling of NYPA power for economic development. The
Company estimates that NYPA power has displaced approximately 400 Gwh of annual
energy sales. The net revenue loss associated with this amount of sales is
approximately $28 million or 1.4% of the Company's 1994 net revenues.
Currently, the potential loss of additional load is limited by conditions in
the Company's transmission agreements with NYPA.
Aside from NUGs, a number of customer groups are seeking to hasten
consideration and implementation of full retail competition. For example, an
energy consultant has petitioned the PSC, seeking alternate sources of power
for Long Island school districts. The County of Nassau has also petitioned the
PSC to authorize retail wheeling for all classes of electric customers in the
county. In addition, several towns on Long Island are investigating
municipalization. Municipalization, in which customers form a
government-sponsored electric supply company, is one form of competition likely
to increase as a result of NEPA. The Town of Southampton and several other
towns in the Company's service territory are considering the formation of a
municipally owned and operated electric authority to replace the services
currently provided by the Company. Suffolk County has also approached FERC to
determine whether it can qualify as a municipal power authority in order to
purchase cheaper electricity from non-Company sources. The Company's
geographic location and the limited electrical interconnections to Long Island
serve to limit the accessibility of its transmission grid to potential
competitors from off the system.
The matters discussed above involve substantial social, economic, legal,
environmental and financial issues. The Company is opposed to any proposal
that merely shifts costs from one group of ratepayers to another, that fails to
enhance the provision of least-cost, efficiently-generated electricity or that
fails to provide the Company's shareowners with an adequate return on and
recovery of their investment. The Company is unable to predict what action, if
any, the PSC or FERC may take regarding any of these matters, or the impact on
the Company's financial condition if some or all of these matters are approved
or implemented by the appropriate regulatory authority.
CONSERVATION SERVICES
In 1993, the Company filed a modified DSM plan with the PSC to support the
objectives of the Company's Electric Rate Plan filed in December 1993. Under
this modified plan, the Company proposed a substantially lower level of
spending than that initially approved for 1994. The PSC did not approve the
Company's proposed plan, but instead issued a ruling in July 1994, which
dictated energy savings targets that were greater than those originally
proposed by the Company. Specifically, the targets for the Company's DSM
programs amounted to a 161.3 MW reduction in coincident peak demand and an
annualized energy savings of 702.6 Gwh by December 31, 1994. The Company was
successful in its DSM efforts.
In 1995, the Company intends to continue to carefully manage DSM expenditures
and more fully transform DSM to a strategic marketing tool which can be used to
position the Company for the future. In these efforts, the Company will act to
further increase the emphasis on education and information programs and further
decrease its emphasis on utility rebate payments. In addition, financing
programs and other cost sharing arrangements will be stressed as a means to
reduce DSM program costs. Finally, DSM programs will be redesigned to enhance
the Company's competitive position through the offering of programs and
services to the Company's customers which promote the efficient use of
electricity, including energy-efficient load growth.
RESULTS OF OPERATIONS
EARNINGS
Summary results of earnings for the years 1994, 1993 and 1992 were as follows:
[Enlarge/Download Table]
(In millions of dollars and shares except earnings per share)
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1994 1993 1992
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Net income $ 301.8 $ 296.6 $ 302.0
Preferred stock dividend
requirements 53.0 56.1 64.0
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Earnings for common stock $ 248.8 $ 240.5 $ 238.0
===================================================================================================================
Average common shares
outstanding 115.9 112.1 111.4
Earnings per common share $ 2.15 $ 2.15 $ 2.14
-------------------------------------------------------------------------------------------------------------------
The Company achieved the same level of earnings per common share in 1994 as in
1993 despite an increase in the average number of common shares outstanding.
This was primarily the result of the Company's cost containment program and the
impact on earnings of positive cash flow from operations, which allowed the
Company to use cash balances to satisfy maturing debt.
The electric business achieved a higher level of earnings in 1994 as compared
to 1993, offset by a decrease in the gas business earnings. The decrease in
gas business earnings in 1994 was the result of several factors including: (i)
a lower allowed return on common equity; (ii) a write-off in 1994, of
previously deferred storm costs and (iii) a provision in the Company's gas rate
structure which became effective December 1, 1993, which requires earnings in
excess of a 10.6% return on common equity be shared equally between the
Company's firm gas customers and its shareowners.
The earnings in the electric business were lower in 1993 when compared to 1992
due primarily to the expensing of previously deferred storm costs, lower
interest rates associated with short-term investments and certain regulatory
adjustments recorded in accordance with the Company's electric rate structure.
The lower level of earnings in the electric business was offset by a
significant increase in earnings in the gas business, resulting from the
continuation of the Company's gas expansion program.
REVENUES
Total revenues, including revenues from recovery of fuel costs, were $3.1
billion, $2.9 billion and $2.6 billion for the years 1994, 1993 and 1992,
respectively.
Electric Revenues
Revenues from the Company's electric operations for the years 1994, 1993 and
1992 were $2.5 billion, $2.4 billion and $2.2 billion, respectively.
In November 1991, the PSC approved the LRPP, which provided the Company with
annual electric rate increases of 4.15%, 4.1% and 4.0% for the rate years
beginning December 1, 1991, 1992 and 1993, respectively. These rate increases
provided $69 million of additional revenues in 1994 as compared to 1993, and
$75 million of additional revenues in 1993 as compared to 1992.
The LRPP contains several regulatory mechanisms that impact the level of
revenues, but have no impact on earnings. The Company's current electric rate
structure provides for a revenue reconciliation, which eliminates the impact on
earnings of experiencing sales that are above or below the levels reflected in
rates. As a result of lower than adjudicated electric sales, the Company
recorded non-cash income, which is included in "Other Regulatory Amortization,"
of $50.9 million, $43.5 million and $78.5 million in 1994, 1993 and 1992,
respectively.
Under the LRPP, base fuel costs collected in rates in excess of actual fuel
costs are applied as a reduction to the RMC. The Company applied $83.9
million, $37.5 million and $22.9 million of amounts collected in excess of
actual fuel costs as a reduction to the RMC for the rate years ended November
30, 1994, 1993 and 1992, respectively.
Under the LRPP, deferred balances associated with the reconciliation of
revenue, expenses and performance incentives in excess of $15 million per annum
are returned to or recovered from the ratepayers through the FCA. During the
period August 1993 through July 1994, the Company collected, through the FCA,
approximately $2.7 million per month for an aggregate of $30.2 million related
to the deferred balances for the rate year ended November 30, 1992. Since
August 1994, the PSC has allowed the Company to continue the collection of a
like amount through the FCA which will continue through the end of the
suspension period. These additional revenues, amounting to approximately $13.4
million through December 1994, were recorded as a reduction to the RMC. The
Company is awaiting PSC approval for the recovery of $48.1 million and $63.6
million for the 1993 and 1994 rate year deferrals. For a further discussion of
the LRPP regulatory mechanisms, see Note 3 of Notes to Financial Statements.
Total electric sales volumes in millions of kWh were 16,382 in 1994, 16,128 in
1993 and 15,667 in 1992. The increase in sales in 1994 and 1993 was primarily
the result of warmer than normal weather experienced in the summer months. The
increases in sales were partially offset by sales lost to non-utility
generators and power displaced by NYPA, discussed above under the heading
"Competitive Environment." In 1994 and 1993, the composition of system sales
was 45% residential and 52% commercial/industrial. In 1992, the composition
was 44% residential and 53% commercial/industrial.
Gas Revenues
Revenues from the Company's gas operations for the years 1994, 1993 and 1992
were $586 million, $529 million and $427 million, respectively.
In December 1993, the PSC approved a three year gas rate settlement between the
Company and the Staff of the PSC. The gas rate settlement provides the Company
with annual gas rate increases of 4.7%, 3.8% and 2.8% for the rate years
beginning December 1, 1993, 1994 and 1995, respectively. The Company had also
received an annual gas rate increase of 7.1% effective December 1, 1992. These
rate increases provided $25 million in additional revenues for 1994 as compared
to 1993, and $35 million in additional revenues for 1993 as compared to 1992.
Total gas firm sales volumes in thousands of dekatherms (Mdth) were 58,889 in
1994, 59,183 in 1993 and 56,292 in 1992. In 1994, firm sales volumes decreased
when compared to 1993 primarily due to warmer weather experienced during the
1994 heating season as compared to 1993, partially offset by the addition of
approximately 8,500 new gas space heating customers resulting from the
continuation of the Company's gas expansion program. The number of monthly
average space heating customers was 273,633, 266,665 and 259,500 for the years
1994, 1993 and 1992, respectively. The Company has a weather normalization
clause which mitigates the impact on revenues of experiencing weather that is
warmer or colder than the "normal" value used for projecting sales. In 1993,
firm sales volumes increased as a result of colder weather experienced during
the 1993 heating season as compared to 1992 combined with additional gas space
heating customers resulting from the Company's gas expansion program.
The Company began selling gas off-system in 1993. Off-system gas sales
revenues were $26 million and $8 million on volumes of 7,232 Mdth and 2,894
Mdth, for the years ended December 31, 1994 and 1993, respectively. Any
profits realized from off-system sales are allocated 85% to ratepayers and 15%
to shareowners.
Recoveries of gas fuel expenses increased revenues by $33 million and $26
million in 1994 and 1993, respectively. In 1994, the increase in the
recoveries of gas fuel expenses was primarily due to increased billed sales
volumes and higher average gas prices,
when compared to 1993. In 1993, the increase was primarily due to higher
average gas prices, when compared to 1992.
OPERATING EXPENSES
Fuel and Purchased Power
Summary of fuel and purchased power expenses for the years 1994, 1993 and 1992
were as follows:
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(In thousands of dollars)
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1994 1993 1992
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Fuel for Electric Operations
Oil $ 145 $ 180 $ 190
Gas 101 93 79
Nuclear 15 13 11
Purchased power 308 293 280
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Total 569 579 560
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Gas fuel 279 249 182
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Total $ 848 $ 828 $ 742
===================================================================================================
Despite an increase in electric sales volumes during 1994 and rising fuel oil
prices, fuel for electric operations decreased primarily as a result of the
Company's efforts to reduce its dependency on oil as the primary fuel for
electric generation. The Company, over the past several years, has refitted
several generating facilities to enable them to burn either oil or natural gas,
depending upon the relative cost of each commodity at any given time.
In addition to the increased use of natural gas, the Company has reduced oil
consumption by using energy generated at Nine Mile Point Nuclear Power Station,
Unit 2 (NMP2) and by purchasing power from other systems, cogenerators and
independent power producers. The total barrels of oil consumed for electric
operations was 7.5 million, 9.7 million and 10.7 million, for the years 1994,
1993 and 1992, respectively.
Cogenerators and independent power producers provided approximately 9% of the
Company's system requirements in 1994, 1993 and 1992. The increase in
purchased power expenses in 1994 is primarily attributable to purchases from
the 136 MW facility in Holtsville, New York, owned by NYPA, constructed for the
benefit of the Company.
Summary of electric fuel and purchased power mix for the years 1994, 1993 and
1992 were as follows:
[Enlarge/Download Table]
(Percent of system energy requirements)
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1994 1993 1992
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Oil 25% 33% 37%
Gas 23 19 19
Nuclear 9 7 6
Purchased power 43 41 38
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Total 100% 100% 100%
==================================================================================================
Gas fuel expenses for gas operations increased by $30 million and $67 million
in 1994 and 1993, respectively. The increase in 1994 is primarily attributable
to the additional fuel costs associated with the Company's off-system gas
sales, while the increase for 1993 was primarily due to significantly higher
gas prices and increased volumes, as a result of colder than normal weather
during the heating season.
Operations and Maintenance Expenses
Operations and maintenance (O&M) expenses, excluding fuel and purchased power,
were $541 million, $522 million and $498 million, for the years 1994, 1993 and
1992, respectively. The increase in O&M for 1994 was primarily due to the
recognition of previously deferred storm costs associated with gas operations,
an increase in costs associated with the Company's gas expansion program, the
recognition of certain costs which exceeded the Company's insurance recoveries,
an increase in employee benefit costs and the effects of inflation. These
higher O&M expenses were partially offset by the continuation of the Company's
cost containment program. The increase in 1993 was principally due to the
recognition of previously deferred storm costs associated with electric
operations, the recording of higher accruals for uncollectible accounts and
higher transmission and distribution costs for both the electric and gas
businesses.
Rate Moderation Component and Related Carrying Charges
In 1994 and 1993, the Company recorded non-cash charges to income of
approximately $198 million and $89 million, respectively, representing the
amortization of the RMC. In 1992, the Company recorded non-cash income of
approximately $30 million, representing the accretion of the RMC. The Company
accrues a carrying charge on the unamortized balance of the RMC which amounted
to $32 million, $40 million and $43 million for the years 1994, 1993 and 1992,
respectively. For further discussion on the RMC, see Notes 1, 2 and 3 of Notes
to Financial Statements.
Other Regulatory Amortization
In 1994, other regulatory amortization was a non-cash charge to income of $4.3
million, compared to a non-cash credit to income of $18.0 million in 1993. The
change reflects an increase in the amortization of LRPP deferrals, higher
amortization of Shoreham post settlement costs, and a non-cash charge to income
reflecting the operation of the interest deferral mechanism, as defined in the
Company's electric rate structure. These items were partially offset by higher
deferred net margin revenues, discussed above under "Revenues."
In 1993, other regulatory amortization was lower than 1992 as a result of lower
net margin revenues and the amortization of the 1992 rate year LRPP deferrals
which began in August 1993. Partially offsetting these items was the
recognition of additional non-cash credits to income resulting from the
operation of the interest deferral mechanism. For a discussion on the
Company's rate mechanisms, see Note 3 of Notes to Financial Statements.
Operating Taxes
Operating taxes were $407 million, $386 million and $389 million, for the years
1994, 1993 and 1992, respectively. The increase in operating taxes of
approximately $21 million in 1994 when compared to 1993 is primarily
attributable to higher gross receipts taxes, resulting from increased revenues,
higher property taxes, additional payroll taxes and higher dividend taxes.
INTEREST EXPENSE
The reduction in interest expense in 1994 when compared to 1993 is primarily
attributable to lower outstanding debt levels. The Company's strategy is to
apply available cash balances toward the satisfaction of debt whenever
practicable. During 1994, the Company used approximately $200 million of cash
on hand and the proceeds from the issuance of 5.1 million shares of common
stock to help lower debt by approximately $300 million. The lower interest
expense also reflects the satisfaction of $175 million of maturing debt in
November 1993, with cash on hand.
The increase in 1993 when compared to 1992 was attributable to higher debt
levels and the conversion in June 1992 of $400 million of tax-exempt securities
from a weekly variable interest rate to a higher thirty year fixed rate. Also
contributing to the increase, was the issuance in November 1992 of thirty year
fixed rate debentures, the proceeds of which were used to eliminate variable
rate bank debt. The conversion of the tax-exempt securities and refinancing of
bank debt was done in order to take advantage of historically low long-term
interest rates. Partially offsetting this increase in interest expense were
savings realized from the effects of the Company's aggressive refinancing of
higher-cost debt in 1993.
ACCOUNTING PRONOUNCEMENTS
Effective January 1, 1993, the Company adopted the provisions of Statement of
Financial Accounting Standards (SFAS) No. 106, Employers' Accounting for
Postretirement Benefits Other Than Pensions. Under a PSC order issued in
response to SFAS No. 106, the Company defers as a regulatory asset the
difference between postretirement benefits expense recorded for accounting
purposes in accordance with SFAS No. 106 and postretirement expenses reflected
in rates. The PSC order also requires that the ongoing annual postretirement
benefit expense be phased into and fully recovered in rates within a five year
period, with the accumulated postretirement benefit obligation being recovered
in rates over a twenty year period. The adoption of SFAS No. 106 had no impact
on net income for the years ended December 31, 1994 and 1993. For a further
discussion of SFAS No. 106, see Notes 1 and 8 of Notes to Financial Statements.
Effective January 1, 1993, the Company adopted SFAS No. 109, Accounting for
Income Taxes. SFAS No. 109 requires utilities to establish deferred tax assets
and liabilities for, among other things, transactions that were not recognized
under Accounting Principles Board Opinion No. 11, Accounting for Income Taxes.
SFAS No. 109 provides that regulatory assets and liabilities may be established
for these specific SFAS No. 109 created deferred tax assets and liabilities
providing that the regulator provides for the future recovery or return of
these amounts through rates. As a result of a PSC order issued in January
1993, providing for the recovery or return of such amounts, the Company has
recorded regulatory tax assets and liabilities to offset the effect of
accumulated deferred tax liabilities and assets created as a result of adopting
SFAS No. 109. The adoption of SFAS No. 109 had no impact on net income for the
years ended December 31, 1994 and 1993. For a further discussion of SFAS No.
109, see Notes 1 and 9 of Notes to Financial Statements.
SELECTED FINANCIAL DATA
Additional information respecting revenues, expenses, electric and gas
operating income and operations data and balance sheet information for the last
five years is provided in Tables 1 through 11 of Item 6, Selected Financial
Data. Information with regard to the Company's business segments for the last
three years is provided in Note 11 of Notes to Financial Statements.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
[Download Table]
Page
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Statement of Income for each of the three years
in the period ended December 31, 1994. 56
Balance Sheet at December 31, 1994 and 1993 57
Statement of Retained Earnings for each of the three
years in the period ended December 31, 1994 59
Statement of Capitalization at December 31, 1994 and 1993 59
Statement of Cash Flows for each of the three years
in the period ended December 31, 1994 61
Notes to Financial Statements 62
Report of Ernst & Young LLP, Independent Auditors. 91
Financial Statements Schedules 92
The following Financial Statement Schedules are
submitted as part of Item 14, "Exhibits, Financial
Statement Schedules and Reports on Form 8-K," of
this annual Report. (All other Financial Statement
Schedules are omitted because they are not applicable,
or the required information appears in the Financial
Statements or the Notes thereto.)
Valuation of Qualifying Accounts (Schedule II) 101
Financial Statements
[Enlarge/Download Table]
Statement of Income (In thousands of dollars except per share amount)
--------------------------------------------------------------------------------------------
For year ended December 31 1994 1993 1992
--------------------------------------------------------------------------------------------
Revenues
Electric $ 2,481,637 $ 2,352,109 $ 2,194,632
Gas 585,670 528,886 427,207
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Total Revenues 3,067,307 2,880,995 2,621,839
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Operating Expenses
Operations - fuel and purchased power 847,986 827,591 741,784
Operations - other 406,014 387,808 372,209
Maintenance 134,640 133,852 125,736
Depreciation and amortization 130,664 122,471 119,137
Base financial component amortization 100,971 100,971 100,971
Rate moderation component amortization 197,656 88,667 (30,444)
Regulatory liability component amortization (79,359) (79,359) (79,359)
1989 Settlement credits amortization (9,214) (9,214) (9,214)
Other regulatory amortization 4,328 (18,044) (22,072)
Operating taxes 406,895 385,847 388,988
Federal income tax - current 10,784 6,324 530
Federal income tax - deferred and other 170,997 178,530 172,468
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Total Operating Expenses 2,322,362 2,125,444 1,880,734
--------------------------------------------------------------------------------------------
Operating Income 744,945 755,551 741,105
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Other Income and (Deductions)
Allowance for other funds used during construction 2,716 2,473 4,725
Rate moderation component carrying charges 32,321 40,004 42,837
Other income and deductions, net 35,343 38,997 29,273
Class Settlement (22,730) (23,178) (22,541)
Federal income tax - deferred and other 5,069 12,578 12,036
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Total Other Income and (Deductions) 52,719 70,874 66,330
--------------------------------------------------------------------------------------------
Income Before Interest Charges 797,664 826,425 807,435
--------------------------------------------------------------------------------------------
Interest Charges and (Credits)
Interest on long-term debt 437,751 466,538 450,621
Other interest 62,345 67,534 62,226
Allowance for borrowed funds used
during construction (4,284) (4,210) (7,386)
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Total Interest Charges and (Credits) 495,812 529,862 505,461
--------------------------------------------------------------------------------------------
Net Income 301,852 296,563 301,974
Preferred stock dividend requirements 53,020 56,108 63,954
--------------------------------------------------------------------------------------------
Earnings for Common Stock $ 248,832 $ 240,455 $ 238,020
--------------------------------------------------------------------------------------------
Average Common Shares Outstanding (000) 115,880 112,057 111,439
--------------------------------------------------------------------------------------------
Earnings per Common Share $ 2.15 $ 2.15 $ 2.14
--------------------------------------------------------------------------------------------
Dividends Declared per Common Share $ 1.78 $ 1.76 $ 1.72
--------------------------------------------------------------------------------------------
See Notes to Financial Statements.
[Enlarge/Download Table]
Balance Sheet (In thousands of dollars)
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Assets At December 31 1994 1993
Utility Plant
Electric $ 3,657,178 $ 3,544,569
Gas 994,742 860,899
Common 232,346 201,418
Construction work in progress 129,824 176,504
Nuclear fuel in process and in reactor 23,251 16,533
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5,037,341 4,799,923
Less - Accumulated depreciation
and amortization 1,538,995 1,452,366
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Total Net Utility Plant 3,498,346 3,347,557
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Regulatory Assets
Base financial component
(less accumulated amortization
of $555,340 and $454,369) 3,483,490 3,584,461
Rate moderation component 463,229 609,827
Shoreham post settlement costs 922,580 777,103
Shoreham nuclear fuel 73,371 75,497
Postretirement benefits other than pensions 412,727 402,921
Regulatory tax asset 1,831,689 1,848,998
Other 354,524 311,832
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Total Regulatory Assets 7,541,610 7,610,639
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Nonutility Property and Other Investments 24,043 23,029
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Current Assets
Cash and cash equivalents 185,451 248,532
Special deposits 27,614 23,439
Customer accounts receivable
(less allowance for doubtful
accounts of $23,365 and $23,889) 245,125 249,074
Other accounts receivable 14,030 12,199
Accrued unbilled revenues 164,379 170,042
Materials and supplies at average cost 74,777 68,882
Fuel oil at average cost 37,723 35,857
Gas in storage at average cost 68,447 75,182
Prepayments and other current assets 33,878 41,652
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Total Current Assets 851,424 924,859
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Deferred Charges
Deferred federal income tax 951,766 1,094,088
Unamortized cost of issuing securities 313,207 350,239
Other 36,284 42,705
---------------------------------------------------------------------------------------------------------------
Total Deferred Charges 1,301,257 1,487,032
---------------------------------------------------------------------------------------------------------------
Total Assets $ 13,216,680 $ 13,393,116
===============================================================================================================
See Notes to Financial Statements.
Page
[Enlarge/Download Table]
(In thousands of dollars)
-------------------------------------------------------------------------------------------------------------------
Capitalization and Liabilities At December 31 1994 1993
Capitalization
Long-term debt $ 5,162,675 $ 4,887,733
Unamortized discount on debt (17,278) (17,393)
-------------------------------------------------------------------------------------------------------------------
5,145,397 4,870,340
-------------------------------------------------------------------------------------------------------------------
Preferred stock - redemption required 644,350 649,150
Preferred stock - no redemption required 63,957 64,038
-------------------------------------------------------------------------------------------------------------------
Total Preferred Stock 708,307 713,188
-------------------------------------------------------------------------------------------------------------------
Common stock 592,083 561,662
Premium on capital stock 1,101,240 1,010,283
Capital stock expense (52,175) (50,427)
Retained earnings 752,480 711,432
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Total Common Shareowners' Equity 2,393,628 2,232,950
-------------------------------------------------------------------------------------------------------------------
Total Capitalization 8,247,332 7,816,478
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Regulatory Liabilities
Regulatory liability component 357,117 436,476
1989 Settlement credits 145,868 155,081
Regulatory tax liability 111,218 114,748
Other 143,611 138,612
-------------------------------------------------------------------------------------------------------------------
Total Regulatory Liabilities 757,814 844,917
-------------------------------------------------------------------------------------------------------------------
Current Liabilities
Current maturities of long-term debt 25,000 600,000
Current redemption requirements of preferred stock 4,800 4,800
Accounts payable and accrued expenses 241,775 277,519
Accrued taxes (including federal income
tax of $28,340 and $28,424) 58,133 52,656
Accrued interest 149,929 142,409
Dividends payable 57,367 54,542
Class Settlement 40,000 30,000
Customer deposits 28,474 27,046
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Total Current Liabilities 605,478 1,188,972
-------------------------------------------------------------------------------------------------------------------
Deferred Credits
Deferred federal income tax 2,941,793 2,932,029
Class Settlement 147,437 164,942
Other 13,204 12,622
-------------------------------------------------------------------------------------------------------------------
Total Deferred Credits 3,102,434 3,109,593
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Operating Reserves
Pensions and other postretirement benefits 453,016 424,442
Claims and damages 50,606 8,714
-------------------------------------------------------------------------------------------------------------------
Total Operating Reserves 503,622 433,156
-------------------------------------------------------------------------------------------------------------------
Commitments and Contingencies - -
-------------------------------------------------------------------------------------------------------------------
Total Capitalization and Liabilities $ 13,216,680 $ 13,393,116
===================================================================================================================
See Notes to Financial Statements.
[Enlarge/Download Table]
Statement of Retained Earnings (In thousands of dollars)
---------------------------------------------------------------------------------------------------------------------
1994 1993 1992
---------------------------------------------------------------------------------------------------------------------
Balance at January 1 $ 711,432 $ 667,988 $ 620,373
Net income for the year 301,852 296,563 301,974
---------------------------------------------------------------------------------------------------------------------
1,013,284 964,551 922,347
Deductions
Cash dividends declared on common stock 207,794 197,236 191,693
Cash dividends declared on preferred stock 53,046 55,861 62,387
Other adjustments (36) 22 279
---------------------------------------------------------------------------------------------------------------------
Balance at December 31 $ 752,480 $ 711,432 $ 667,988
=====================================================================================================================
See Notes to Financial Statements.
[Enlarge/Download Table]
Statement of Capitalization Shares Outstanding (In thousands of dollas)
---------------------------------------------------------------------------------------------------------------------
At December 31 1994 1993 1994 1993
---------------------------------------------------------------------------------------------------------------------
Common Shareowners' Equity
Common stock, $5.00 par value 118,416,606 112,332,490 $ 592,083 $ 561,662
Premium on capital stock 1,101,240 1,010,283
Capital stock expense (52,175) (50,427)
Retained earnings 752,480 711,432
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Total Common Shareowners' Equity 2,393,628 2,232,950
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Preferred Stock - Redemption Required
Par value $100 per share
7.40% Series L 182,000 192,500 18,200 19,250
8.50% Series R 75,000 112,500 7,500 11,250
7.66% Series CC 570,000 570,000 57,000 57,000
Less - Sinking fund requirement 4,800 4,800
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77,900 82,700
---------------------------------------------------------------------------------------------------------------------
Par value $25 per share
7.95% Series AA 14,520,000 14,520,000 363,000 363,000
$1.67 Series GG 880,000 880,000 22,000 22,000
$1.95 Series NN 1,554,000 1,554,000 38,850 38,850
7.05% Series QQ 3,464,000 3,464,000 86,600 86,600
6.875% Series UU 2,240,000 2,240,000 56,000 56,000
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566,450 566,450
---------------------------------------------------------------------------------------------------------------------
Total Preferred Stock - Redemption Required 644,350 649,150
---------------------------------------------------------------------------------------------------------------------
Preferred Stock - No Redemption Required
Par value $100 per share
5.00% Series B 100,000 100,000 10,000 10,000
4.25% Series D 70,000 70,000 7,000 7,000
4.35% Series E 200,000 200,000 20,000 20,000
4.35% Series F 50,000 50,000 5,000 5,000
5 1/8% Series H 200,000 200,000 20,000 20,000
5 3/4% Series I - Convertible 19,569 20,375 1,957 2,038
---------------------------------------------------------------------------------------------------------------------
Total Preferred Stock - No Redemption Required 63,957 64,038
---------------------------------------------------------------------------------------------------------------------
Total Preferred Stock $ 708,307 $ 713,188
---------------------------------------------------------------------------------------------------------------------
See Notes to Financial Statements.
[Enlarge/Download Table]
(In thousands of dollars)
------------------------------------------------------------------------------------------------------------
At December 31 Maturity Interest Rate Series 1994 1993
------------------------------------------------------------------------------------------------------------
First Mortgage Bonds (excludes Pledged Bonds)
June 1, 1994 4 5/8% N $ - $ 25,000
June 1, 1995 4.55% O 25,000 25,000
March 1, 1996 5 1/4% P 40,000 40,000
April 1, 1997 5 1/2% Q 35,000 35,000
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Total First Mortgage Bonds 100,000 125,000
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General and Refunding Bonds
May 1, 1996 8 3/4% 415,000 415,000
February 15, 1997 8 3/4% 250,000 250,000
April 15, 1998 7 5/8% 100,000 -
May 15, 1999 7.85% 56,000 56,000
April 15, 2004 8 5/8% 185,000 -
May 15, 2006 8.50% 75,000 75,000
July 15, 2008 7.90% 80,000 80,000
May 1, 2021 9 3/4% 415,000 415,000
July 1, 2024 9 5/8% 375,000 375,000
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Total General and Refunding Bonds 1,951,000 1,666,000
------------------------------------------------------------------------------------------------------------
Debentures
June 15, 1994 10.25% - 400,000
November 15, 1994 11.75% - 175,000
June 15, 1999 10.875% - 30,545
July 15, 1999 7.30% 397,000 397,000
January 15, 2000 7.30% 36,000 36,000
July 15, 2001 6.25% 145,000 145,000
March 15, 2003 7.05% 150,000 150,000
March 1, 2004 7.00% 59,000 59,000
June 1, 2005 7.125% 200,000 200,000
March 1, 2007 7.50% 142,000 142,000
June 15, 2019 11.375% - 4,513
July 15, 2019 8.90% 420,000 420,000
November 1, 2022 9.00% 451,000 451,000
March 15, 2023 8.20% 270,000 270,000
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Total Debentures 2,270,000 2,880,058
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Authority Financing Notes
Industrial Development Revenue Bonds
December 1, 2006 7.5% 1976 A,B 2,000 2,000
Pollution Control Revenue Bonds
December 1, 2006 7.5% 1976 A 28,375 28,375
December 1, 2009 7.8% 1979 B 19,100 19,100
October 1, 2012 8 1/4% 1982 17,200 17,200
March 1, 2016 3.0% 1985 A,B 150,000 150,000
Electric Facilities Revenue Bonds
September 1, 2019 7.15% 1989 A,B 100,000 100,000
June 1, 2020 7.15% 1990 A 100,000 100,000
December 1, 2020 7.15% 1991 A 100,000 100,000
February 1, 2022 7.15% 1992 A,B 100,000 100,000
August 1, 2022 6.9% 1992 C,D 100,000 100,000
November 1, 2023 5.45% 1993 A 50,000 50,000
November 1, 2023 4.90% 1993 B 50,000 50,000
October 1, 2024 5.40% 1994 A 50,000 -
------------------------------------------------------------------------------------------------------------
Total Authority Financing Notes 866,675 816,675
------------------------------------------------------------------------------------------------------------
Unamortized Discount on Debt (17,278) (17,393)
------------------------------------------------------------------------------------------------------------
Total 5,170,397 5,470,340
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Less Current Maturities 25,000 600,000
------------------------------------------------------------------------------------------------------------
Total Long-Term Debt 5,145,397 4,870,340
------------------------------------------------------------------------------------------------------------
Total Capitalization $ 8,247,332 $7,816,478
------------------------------------------------------------------------------------------------------------
See Notes to Financial Statements.
[Enlarge/Download Table]
Statement of Cash Flows (In thousands of dollars)
--------------------------------------------------------------------------------------------------------------
For year ended December 31 1994 1993 1992
--------------------------------------------------------------------------------------------------------------
Operating Activities
Net Income $ 301,852 $ 296,563 $ 301,974
Adjustments to reconcile net income to net
cash provided by operating activities
Provision for doubtful accounts 19,542 18,555 16,329
Depreciation and amortization 130,664 122,471 119,137
Base financial component amortization 100,971 100,971 100,971
Rate moderation component amortization 197,656 88,667 (30,444)
Regulatory liability component amortization (79,359) (79,359) (79,359)
1989 Settlement credits amortization (9,214) (9,214) (9,214)
Other regulatory amortizations 4,328 (18,044) (22,072)
Rate moderation component carrying charges (32,321) (40,004) (42,837)
Class Settlement 22,730 23,178 22,541
Amortization of cost of issuing and redeeming securities 46,237 52,063 41,204
Federal income tax - deferred and other 165,928 165,952 160,432
Allowance for other funds used during construction (2,716) (2,473) (4,725)
Gas cost adjustment 11,709 (3,499) (24,142)
Other 37,538 15,200 1,035
Changes in operating assets and liabilities
Accounts receivable (17,353) (65,898) (14,275)
Class Settlement (30,235) (25,302) (19,039)
Accrued unbilled revenues 5,663 (26,870) (6,607)
Materials and supplies, fuel oil and gas in storage (1,026) 5,265 (10,933)
Prepayments and other current assets 7,774 (1,250) (5,548)
Accounts payable and accrued expenses (44,598) (8,800) 62,513
Accrued taxes 5,477 (14,869) 7,351
Other (5,498) (11,290) 25,772
--------------------------------------------------------------------------------------------------------------
Net Cash Provided by Operating Activities 835,749 582,013 590,064
--------------------------------------------------------------------------------------------------------------
Investing Activities
Construction and nuclear fuel expenditures (276,954) (302,220) (268,179)
Shoreham post settlement costs (167,367) (207,114) (227,658)
Other (1,349) (934) (1,484)
--------------------------------------------------------------------------------------------------------------
Net Cash Used in Investing Activities (445,670) (510,268) (497,321)
--------------------------------------------------------------------------------------------------------------
Financing Activities
Proceeds from issuance of long-term debt 331,326 1,089,770 1,659,928
Proceeds from sale of common stock 118,108 14,323 5,670
Proceeds from sale of preferred stock 201,709 411,373
Redemption of long-term debt (635,058) (960,000) (1,344,283)
Redemption of preferred stock (4,800) (205,600) (389,428)
Common stock dividends paid (205,086) (195,794) (190,477)
Preferred stock dividends paid (52,927) (56,727) (69,923)
Cost of issuing and redeeming securities (5,871) (17,036) (166,066)
Other 1,148 (3,343) 1,850
--------------------------------------------------------------------------------------------------------------
Net Cash Used in Financing Activities (453,160) (132,698) (81,356)
--------------------------------------------------------------------------------------------------------------
Net (Decrease) Increase in Cash and Cash Equivalents $ (63,081) $ (60,953) $ 11,387
==============================================================================================================
Cash and cash equivalents at January 1 $ 248,532 $ 309,485 $ 298,098
Net (decrease) increase in cash and cash equivalents (63,081) (60,953) 11,387
--------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at December 31 $ 185,451 $ 248,532 $ 309,485
--------------------------------------------------------------------------------------------------------------
Interest paid, before reduction for the allowance
for borrowed funds used during constuction $ 446,340 $ 469,978 $ 424,842
Federal income tax - paid $ 10,780 $ 6,000 $ 2,100
Federal income tax - refunded $ -- $ 1,000 $ 1,566
--------------------------------------------------------------------------------------------------------------
See Notes to Financial Statements.
NOTES TO FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
REGULATION
The Company's accounting policies conform to generally accepted accounting
principles as they apply to a regulated enterprise. Its accounting records are
maintained in accordance with the Uniform Systems of Accounts prescribed by the
Public Service Commission of the State of New York (PSC) and the Federal Energy
Regulatory Commission (FERC).
REGULATORY ASSETS AND LIABILITIES
General
The Company's Balance Sheet reflects the rate actions of its regulators through
the creation of regulatory assets and liabilities. Regulatory assets are
generally created whenever it is probable that the regulators will permit the
recovery through rates of a previously incurred cost that would otherwise be
charged to expense. Regulatory liabilities are generally created whenever it
is probable that the regulators will require a return through rates of revenues
or gains that would otherwise be recorded to income.
Base Financial Component and Rate Moderation Component
Pursuant to the 1989 Settlement, the Company recorded a regulatory asset known
as the Financial Resource Asset (FRA). The FRA is designed to provide the
Company with sufficient cash flows to assure its financial recovery. The FRA
has two components, the Base Financial Component (BFC) and the Rate Moderation
Component (RMC).
The BFC represents the present value of the future net-after-tax cash flows
which the Rate Moderation Agreement (RMA), one of the constituent documents of
the 1989 Settlement, provided the Company for its financial recovery. The BFC
was granted rate base treatment under the terms of the RMA and is included in
the Company's revenue requirements through an amortization included in rates
over forty years on a straight-line basis which began July 1, 1989.
The RMC reflects the difference between the Company's revenue requirements
under conventional ratemaking and the revenues resulting from the
implementation of the rate moderation plan provided for in the RMA. For a
further discussion of the 1989 Settlement and FRA, see Note 2.
Shoreham Post Settlement Costs
The balance consists of Shoreham Nuclear Power Station (Shoreham)
decommissioning costs, fuel disposal costs, payments in lieu of taxes, carrying
charges and other costs. These costs are being capitalized and amortized and
recovered through rates over a forty year period on a straight-line remaining
life basis which began July 1, 1989.
Shoreham Nuclear Fuel
The balance principally reflects the unamortized portion of Shoreham nuclear
fuel which was reclassified from Nuclear Fuel in Process and in Reactor at the
time of the 1989 Settlement. This amount is being amortized, and recovered
through rates over a forty year period on a straight-line remaining life basis
which began July 1, 1989.
Postretirement Benefits Other Than Pensions
Under a PSC order issued in response to the Financial Accounting Standards
Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 106,
Employers' Accounting for Postretirement Benefits Other Than Pensions, the
Company defers as a regulatory asset the difference between postretirement
benefit expense recorded for accounting purposes in accordance with SFAS No.
106 and postretirement benefit expense reflected in rates. Pursuant to the PSC
order, the ongoing annual postretirement benefit expense must be phased into
and fully recovered in rates within a five year period, with the accumulated
postretirement obligation being recovered in rates over a twenty year period.
For a further discussion of SFAS No. 106, see Note 8.
Regulatory Tax Asset/Liability
SFAS No. 109, Accounting for Income Taxes, requires utilities to establish
deferred tax assets and liabilities for, among other things, transactions that
did not give rise to deferred tax assets and liabilities under Accounting
Principles Board (APB) Opinion No. 11, Accounting for Income Taxes. SFAS No.
109 provides that regulatory assets and liabilities may be established for
these specific SFAS No. 109 created deferred tax assets and liabilities
providing that the regulator provides for the future recovery or return of
these amounts through rates. As a result of a PSC order issued in January
1993, providing for the recovery or return of such amounts, the Company has
recorded regulatory tax assets and liabilities to offset the effect of
accumulated deferred tax liabilities and assets created as a result of adopting
SFAS No. 109.
The tax effects of other differences between income for financial statement
purposes and for federal income tax purposes are accounted for as current
adjustments in federal income tax provisions.
Regulatory Liability Component
Pursuant to the 1989 Settlement, certain tax benefits attributable to the
Shoreham abandonment are to be shared between ratepayers and shareowners. A
regulatory liability of approximately $794 million was recorded in June 1989 to
preserve an amount equivalent to the ratepayer tax benefits attributable to the
Shoreham abandonment. This amount is being amortized over a ten year period on
a straight-line basis which began July 1, 1989.
1989 Settlement Credits
The balance represents the unamortized portion of an adjustment of the book
write-off to the negotiated 1989 Settlement amount. A portion of this amount
is being amortized over a ten year period which began on
July 1, 1989. The remaining portion is not currently being recognized for
ratemaking purposes.
UTILITY PLANT
Additions to and replacements of utility plant are capitalized at original
cost, which includes material, labor, indirect costs associated with an
addition or replacement and an allowance for the cost of funds used during
construction. The cost of renewals and betterments relating to units of
property is added to utility plant. The cost of property replaced, retired or
otherwise disposed of is deducted from utility plant and, generally, together
with dismantling costs less any salvage, is charged to accumulated
depreciation. The cost of repairs and minor renewals is charged to maintenance
expense. Mass properties (such as poles, wire and meters) are accounted for on
an average unit cost basis by year of installation.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION
The Uniform Systems of Accounts defines the allowance for funds used during
construction (AFC) as the net cost of borrowed funds for construction purposes
and a reasonable rate of return upon the utility's equity when so used. AFC is
not an item of current cash income. AFC is computed monthly using a rate
permitted by FERC on a portion of construction work in progress. The average
annual AFC rate, without giving effect to compounding, was 9.18%, 9.73% and
9.98% for the years 1994, 1993 and 1992, respectively.
DEPRECIATION
The provisions for depreciation result from the application of straight-line
rates to the original cost, by groups, of depreciable properties in service.
The rates are determined by age-life studies performed annually on depreciable
properties. Depreciation for electric properties was equivalent to
approximately 3.0%, 3.0% and 3.2% of respective average depreciable plant costs
for the years 1994, 1993 and 1992. Depreciation for gas properties was
equivalent to approximately 2.0%, 2.0% and 2.6% of respective average
depreciable plant costs for the years 1994, 1993 and 1992.
CASH AND CASH EQUIVALENTS
Cash equivalents are highly liquid investments with maturities of three months
or less when purchased. The carrying amount approximates fair value because of
the short maturity of these investments.
FAIR VALUES OF FINANCIAL INSTRUMENTS
The fair values for the Company's long-term debt and redeemable preferred stock
are based on quoted market prices, where available. The fair values for all
other long-term debt and redeemable preferred stock are estimated using
discounted cash flow analyses which are based upon the Company's current
incremental borrowing rate for similar types of securities.
CAPITALIZATION - PREMIUMS, DISCOUNTS AND EXPENSES
Premiums or discounts and expenses related to the issuance of long-term debt
are amortized over the life of each issue. Unamortized premiums or discounts
and expenses related to issues of long-term debt that are refinanced are
amortized and recovered through rates over the shorter life of either the
redeemed issue or the new issue. Capital stock expense and redemption costs
related to certain issues of preferred stock that have been refinanced as well
as the cost of issuance of the preferred stock issued are recorded as deferred
charges. These amounts are being amortized and recovered through rates over
the shorter life of the redeemed issue or the new issue.
REVENUES
The Company accrues electric and gas revenues for services rendered to
customers but not billed at month-end. The Company's electric rate structure,
discussed in Note 3, provides for a revenue reconciliation mechanism which
eliminates the impact on earnings of experiencing electric sales that are above
or below the levels reflected in rates. The Company's gas structure provides
for a weather normalization clause, which reduces the impact on revenues of
experiencing weather which is warmer or colder than the "normal" value used for
projecting sales.
FUEL COST ADJUSTMENTS
The Company's electric and gas tariffs include fuel cost adjustment (FCA)
clauses which provide for the disposition of the difference between actual fuel
costs and the fuel costs allowed in the Company's base tariff rates (base fuel
costs). The Company defers these differences to future periods in which they
will be billed or credited to customers, except for base electric fuel costs in
excess of actual electric fuel costs, which are currently credited to the RMC
as incurred.
FEDERAL INCOME TAX
Effective January 1, 1993, the Company adopted SFAS No. 109. As permitted
under SFAS No. 109, the Company elected not to restate the financial statements
of prior years.
The Company provided deferred federal income taxes with respect to certain
items of income and expense that are reported in different years for financial
statement purposes and for federal income tax purposes.
The Company defers the benefit of 60% of pre-1982 gas and pre-1983 electric and
100% of all other investment tax credits, with respect to regulated properties,
when realized on its tax returns. Accumulated deferred investment tax credits
are amortized ratably over the lives of the related properties.
For ratemaking purposes, the Company provides deferred federal income taxes
with respect to certain differences between income before income taxes and
taxable income in certain instances when approved by the PSC, as disclosed in
Note 9. Also certain accumulated deferred federal income taxes are deducted
from rate base and amortized or otherwise applied as a reduction (increase) in
federal income tax expense in future years.
RESERVES FOR CLAIMS AND DAMAGES
Losses arising from claims against the Company, including workers' compensation
claims, property damage, extraordinary storm costs and general liability
claims, are partially self-insured. Reserves for these claims and damages are
based on, among other things, experience, risk of loss and the ratemaking
practices of the PSC. Extraordinary storm losses incurred by the Company are
partially insured by certain commercial insurance carriers. These insurance
carriers provide partial insurance coverage for individual storm losses to the
Company's transmission and distribution system between $5 million and $50
million. Storm losses which are outside of the above-mentioned range are
self-insured by the Company. The Company is currently assessing its storm
insurance requirements, as current policies expire March 1, 1995.
RECLASSIFICATIONS
Certain prior year amounts have been reclassified in the financial statements
to be consistent with the current year's presentation.
NOTE 2. THE 1989 SETTLEMENT
On February 28, 1989, the Company and the State of New York entered into the
1989 Settlement resolving certain issues relating to the Company and providing,
among other matters, for the financial recovery of the Company and for the
transfer of Shoreham and its subsequent decommissioning. Upon the
effectiveness of the 1989 Settlement, in June 1989, the Company simultaneously
recorded on its Balance Sheet the retirement of its investment of approximately
$4.2 billion principally in Shoreham and the establishment of the FRA.
The BFC, a component of the FRA, as initially established, represents the
present value of the future net-after-tax cash flows which the RMA provided the
Company for its financial recovery. The BFC was granted rate base treatment
under the terms of the RMA and is included in the Company's revenue
requirements through an amortization included in rates over forty years on a
straight-line basis that began July 1, 1989. At December 31, 1994 and 1993,
the unamortized balance of the BFC was approximately $3.5 billion and $3.6
billion, respectively.
The RMC, a component of the FRA, reflects the difference between the Company's
revenue requirements under conventional ratemaking and the revenues resulting
from the implementation of the rate moderation plan provided for in the RMA.
Prior to December 31, 1992, the RMC had increased as the difference between
revenues resulting from the implementation of the rate moderation plan provided
for in the RMA and revenue requirements under conventional ratemaking, together
with a carrying charge equal to the allowed rate of return on rate base, was
deferred. The RMC had provided the Company with a substantial amount of
non-cash earnings from the effective date of the 1989 Settlement through
December 31, 1992. Subsequent to December 31, 1992, the RMC balance had been
decreasing as revenues resulting from the operation of the rate moderation plan
exceeded revenue requirements under conventional ratemaking. The RMC is
currently adjusted, on a monthly basis, for the Company's share of certain Nine
Mile Point Nuclear Power Station, Unit 2 (NMP2) operations and maintenance
expenses, fuel credits resulting from the Company's electric fuel cost
adjustment clause discussed in Note 1 and gross receipts tax adjustments
related to the FRA. At December 31, 1994 and 1993, the RMC balance was $463
million and $610 million, respectively. For a further discussion of the impact
on the amortization of the RMC under the Long Island Lighting Company
Ratemaking and Performance Plan (LRPP) and the Company's Electric Rate Plan for
the three year period beginning December 1, 1994, see Note 3.
On February 29, 1992, the Company transferred ownership of Shoreham to the Long
Island Power Authority (LIPA), an agency of the State of New York. Pursuant to
the 1989 Settlement, the Company has funded the decommissioning of Shoreham.
Based on the latest available information, LIPA has reported that the cost of
decommissioning Shoreham, which is essentially complete, totaled approximately
$181 million, excluding the costs associated with the disposal of Shoreham's
fuel which was also completed in 1994 and cost approximately $112 million.
LIPA anticipates that the Nuclear Regulatory Commission (NRC) will terminate
its license for Shoreham during 1995.
NOTE 3. RATE MATTERS
ELECTRIC
Long Island Lighting Company Ratemaking and Performance Plan
Pursuant to the 1989 Settlement, discussed in Note 2, the Company received
electric rate increases as contemplated by the RMA for each of the three rate
years in the period ended November 30, 1991. The RMA contemplates that the
Company will apply to the PSC for targeted annual rate increases of 4.5% to
5.0% in each year for an eight year period beginning December 1, 1991. In
November 1991, the PSC approved the LRPP which provided annual electric rate
increases of 4.15%, 4.1% and 4.0%, respectively, for each of the three rate
years in the period beginning December 1, 1991, with an allowed return on
common equity from electric operations of 11.6% for each of the three rate
years. After giving effect to the reductions required by the Class Settlement
discussed in Note 4, the Company's annual electric rate increases were
approximately 4.15%, 3.9% and 3.9%, with an allowed return on common equity
from electric operations of 10.92%, 10.72% and 10.58%, for the rate years
beginning December 1, 1991, 1992 and 1993, respectively.
The LRPP was designed to be consistent with the RMA's long term goals. One
principal objective of the LRPP was to reassign risk so that the Company
assumes the responsibility for risks within the control of management, whereas
risks largely beyond the control of management would be assumed by the
ratepayers. The LRPP reflects an update of the long range forecast of the
Company's revenue requirements which was the basis of the RMA's initial three
rate increases. The LRPP contains three major components--revenue
reconciliation, expense attrition and reconciliation and performance
incentives.
Revenue reconciliation is provided through a mechanism that eliminates the
impact of experiencing electric sales that are above or below the LRPP forecast
by providing a fixed annual net margin level (defined as sales revenues, net of
fuel and gross receipts taxes) that the Company will receive under the LRPP.
The differences between the actual electric net revenues and the annual net
margin level are deferred on a monthly basis during the rate year.
The expense attrition and reconciliation component permits the Company to make
adjustments for certain expenses recognizing that certain cost increases are
unavoidable due to inflation and changes in the business. The LRPP includes
the annual reconciliation of certain expenses for wage rates, property taxes,
interest costs and demand side management (DSM) costs. The LRPP also provides
for the deferral and amortization of certain costs for enhanced reliability and
production operations and maintenance expenses and the application of an
inflation index to other expenses for the rate years beginning December 1, 1992
and 1993.
Under the performance incentive component of the LRPP, the Company is allowed
to earn for each rate year up to 60 additional basis points, or forfeit up to
38 basis points, of the allowed return on common equity as a result of its
performance within certain incentive and/or penalty programs. These programs
consist of a customer service program, a time of-use program, a partial pass
through fuel cost incentive plan, a DSM program and, effective December 1,
1993, an electric transmission and distribution reliability plan. These
incentives and/or penalties, except
for incentives earned under the DSM program, are determined on a monthly basis
during the rate year and deferred until final approval from the PSC. The
incentives earned from the DSM program are collected in rates on a monthly
basis through the FCA. Based upon the Company's performance within these
programs, the Company earned a total of 50 and 49 basis points or approximately
$9.2 million, net of tax effects, for each of the rate years ended November 30,
1994 and 1993. For the rate year ended November 30, 1992 the Company earned a
total of 23 basis points or approximately $4.3 million, net of tax effects.
The deferred balances resulting from the net margin, property taxes, interest
costs, wage rates, performance incentives and associated carrying charges,
excluding DSM incentives, are netted at the end of each rate year. The LRPP
established a band whereby the first $15 million of the total net deferrals are
used to increase or decrease the RMC balance. The LRPP provides for the
disposition of the total net deferrals in excess of the $15 million band. Upon
approval by the PSC, the total net deferrals in excess of $15 million are
refunded to or recovered from the ratepayers through the FCA over a twelve
month period.
The Company recorded deferred balances of approximately $45.2 million, $63.1
million and $78.6 million of the total net deferrals for the rate years ended
November 30, 1992, 1993 and 1994, respectively. The first $15 million of the
total net deferrals has been recorded for the rate years ended November 30,
1992 and 1993 and upon approval by the PSC of the Company's reconciliation
filing will be recorded for the rate year ended November 30, 1994 as an
increase to the RMC with the remaining net deferrals of $30.2 million, $48.1
million and $63.6 million, respectively, recovered from the ratepayers through
the FCA. As of July 31, 1994, the Company has fully collected the November 30,
1992 net deferrals through the FCA and is awaiting PSC approval for the
collection of the 1993 and 1994 rate year net deferrals through the FCA.
Effective August 1994, the PSC has allowed the Company to continue the
collection of a like amount of the total net deferrals related to the rate year
ended November 30, 1992 through the FCA. These additional revenues amounting
to approximately $13.4 million through December 1994 were recorded as a
reduction to the RMC. The Company expects to collect the 1993 rate year net
deferrals of $48.1 million by November 30, 1995 and the 1994 rate year net
deferrals of $63.6 million over the twelve month period ending November 30,
1996.
The LRPP contains a mechanism whereby earnings in excess of the allowed return
on common equity of 11.6%, excluding the impacts of the various incentive
and/or penalty programs, are shared equally between ratepayers and shareowners.
The Company earned $8.9 million and $21.4 million, net of tax effects, for the
rate years ended November 30, 1993 and 1992, respectively, in excess of its
allowed return on common equity. The amount in excess of the allowed return on
common equity was shared equally between ratepayers (by a reduction to the RMC)
and shareowners for the rate years ended November 30, 1993, and 1992. For the
rate year ended November 30, 1994, the Company did not earn in excess of its
allowed return on common equity.
To assist in the recovery of the RMC balance under the rates provided by the
LRPP, the Company, in accordance with the LRPP, has credited the RMC with
several deferred ratepayer benefits. In December 1994, the Company applied a
total of approximately $5.1 million of net deferred ratepayer benefits to the
RMC including DSM revenues overcollected in the 1994 rate year. In December
1993 and 1992, the Company reduced the RMC by
approximately $10.1 million and $22.5 million representing various deferred
ratepayer benefits including the ratepayers portion of the excess earnings for
the rate years ended November 30, 1993 and 1992, respectively.
Electric Rate Plan
In December 1993, the Company filed a three year Electric Rate Plan with the
PSC for the period beginning December 1, 1994 that minimizes future electric
rate increases while retaining consistency with the RMA's objective of the
restoration of the Company's financial health. The Electric Rate Plan requests
an allowed return on common equity of 11.0% and provides for base rates to be
frozen in years one and two and an overall rate increase of 4.3% in the third
year. Although base electric rates would be frozen during the first two years
of the Electric Rate Plan, annual rate increases of approximately 1% are
expected to result from the operation of the Company's FCA. The FCA captures,
among other things, amounts to be recovered from or refunded to ratepayers in
excess of $15 million which result from the reconciliation of revenues, certain
expenses and earned performance incentive components, discussed above.
The Company's Electric Rate Plan reflects four underlying objectives:
(i) to limit the balance of RMC during the three year period to no more than
its 1992 peak balance of $652 million; (ii) to recover the RMC within the time
frame established in the 1989 Settlement; (iii) to minimize, beginning in the
third year of the Electric Rate Plan, the final three rate increases
contemplated in the 1989 Settlement that follow the two year rate freeze
period; and (iv) to continue the Company's gradual return to financial health.
The Electric Rate Plan provides for, with some modifications, the continuation
of the LRPP revenue and expense reconciliations and performance incentives.
The Electric Rate Plan includes the annual reconciliation of certain expenses
for property taxes, interest costs, DSM costs and the deferral and amortization
of certain costs for enhanced reliability. The Company would be allowed to
earn for the three rate years under the Electric Rate Plan up to 50 additional
basis points, excluding incentives under the DSM program, or forfeit up to 47
basis points of the allowed return on common equity of 11.0% as a result of the
Company's performance within certain performance programs. These programs
consist of a customer service program, a partial pass through fuel cost
incentive plan, a DSM program and an electric transmission and distribution
reliability plan.
The Company's Electric Rate Plan provides for lower annual electric rate
increases than originally anticipated under the 1989 Settlement. However, as a
result of changes in certain assumptions upon which the RMA was based, their
impact on the RMC and the Company's plans to reduce DSM, operations and
maintenance and capital expenditures, the Company has determined that the
overall objectives of the RMA can be met under the Electric Rate Plan. As a
result of lower than originally anticipated inflation rates, interest costs,
property taxes, fuel costs and return on common equity allowed by the PSC, the
RMC, which originally had been anticipated to peak at $1.2 billion in 1994,
peaked at $652 million in 1992. With the exception of a projected increase in
1995 and 1996, which is not now anticipated to cause the RMC to increase above
its $652 million peak, the RMC is expected to decline until it is fully
amortized.
Under the Electric Rate Plan, the recovery of the RMC would be extended, if
necessary, for an additional period of not more than three years beyond the
approximate ten year period envisioned in the RMA. The actual length of the
RMC extension will depend on the extent to which the assumptions underlying the
Electric Rate Plan materialize. The Company's current projections indicate
that the RMC will be recovered in eleven years.
The staff of the PSC (Staff) and other intervening parties filed testimony in
response to the Company's Electric Rate Plan. Staff concurs with the Company's
proposal for an 11.0% return on common equity in each of the three years and
has reaffirmed its commitment to the principles of the RMA, including the full
recovery of the RMC within the time frame established by the RMA. However,
Staff has recommended an overall zero percent rate increase for the first two
years, contrasted with the Company's proposal for a base rate freeze with FCA
adjustments of approximately 1% in years one and two, as described above.
Staff did not make a recommendation for the level of rate relief in the third
year.
In September 1994, three Administrative Law Judges (ALJs) of the PSC issued a
recommended decision to the PSC with respect to the Company's Electric Rate
Plan. The ALJs agreed with the Company's proposed 11.0% return on common
equity and its proposal to freeze base electric rates for the first rate year.
While no explicit recommendation was made concerning the second year, the
recommended decision implies that base rates could remain frozen for the second
rate year as well.
With respect to the third rate year beginning December 1, 1996, the ALJs
determined that it was not appropriate for them to issue a recommendation
since, in their opinion, the Company's revenue requirements for the third rate
year cannot be precisely determined at this time. Alternatively, the ALJs
encouraged the Company and other parties in this proceeding to negotiate a
settlement concerning any rate increase for the third rate year.
The PSC had been expected to issue a final order on the Company's rate proposal
before November 29, 1994, the date that the statutory suspension period was
scheduled to terminate. However, in order to accommodate further settlement
negotiations in the proceeding, the Company has requested extensions through
April 1995, which were granted by the PSC. The Company's offers to extend the
suspension period were conditioned upon the continuation of the current LRPP
rate mechanisms. Although the ultimate outcome of the Electric Rate Plan
cannot be predicted, the Company expects that any PSC order will be consistent
with the provisions of the RMA respecting the recovery of the FRA and other
1989 Settlement deferred charges.
GAS
In December 1993, the PSC approved a three year gas rate settlement between the
Company and the Staff of the PSC. The gas rate settlement provides that the
Company receive, for each of the rate years beginning December 1, 1993, 1994
and 1995, annual gas rate increases of 4.7%, 3.8% and 2.8%, respectively. In
the determination of the revenue requirements for the gas rate settlement an
allowed return on common equity of 10.1% was used. The gas rate decision also
provides that earnings in excess of a 10.6% return on common equity in any of
the three rate years covered by the settlement be shared equally between the
Company's firm gas customers and its shareowners. For the rate year ended
November 30, 1994, the
Company earned $9.2 million, net of tax effects, in excess of the 10.6% return
on common equity. The firm gas customers' portion of these excess earnings
amounting to $4.6 million, net of tax effects, has been deferred until its
final disposition is determined by the PSC.
NOTE 4. THE CLASS SETTLEMENT
The Class Settlement, which became effective on June 28, 1989, resolved a civil
lawsuit against the Company brought under the federal Racketeer Influenced and
Corrupt Organizations Act. The lawsuit which the Class Settlement resolved had
alleged that the Company made inadequate disclosures before the PSC concerning
the construction and completion of nuclear generating facilities. The Class
Settlement provides the Company's electric ratepayers with reductions,
aggregating $390 million, that are being reflected as adjustments to their
monthly electric bills over a ten year period which began on June 1, 1990.
The reductions which begin in each of the remaining twelve month periods are as
follows:
[Download Table]
June 1995 $40 million
June 1996 50 million
June 1997 60 million
June 1998 60 million
June 1999 60 million
Upon its effectiveness, the Company recorded its liability for the Class
Settlement on a present value basis at $170 million and simultaneously recorded
a charge to income (net of tax effects of $57 million) of approximately $113
million. Each month the Company records the changes in the present value of
its liability that results from the passage of time and from monthly
reductions. The Company expects the Class Settlement liability will be fully
satisfied by May 31, 2000.
In accordance with the Class Settlement, the Company, in 1990, established a
$10 million fund to reimburse former electric ratepayers entitled to refunds
under the Class Settlement. At December 31, 1994, approximately $4.5 million
remains undistributed in the fund. Pursuant to the terms of the Class
Settlement, the undistributed portion of the net fund balance will be used to
reduce ratepayers' bills upon the Company's receipt of the funds from the
trustee.
NOTE 5. NINE MILE POINT NUCLEAR POWER STATION, UNIT 2
The Company has an 18% undivided interest in NMP2 which is operated by Niagara
Mohawk Power Corporation (NMPC) near Oswego, New York. Ownership of NMP2 is
shared by five cotenants: the Company (18%), NMPC (41%), New York State
Electric & Gas Corporation (18%), Rochester Gas and Electric Corporation (14%)
and Central Hudson Gas & Electric Corporation (9%). At December 31, 1994, the
Company's utility plant investment in NMP2 was $749 million, net of accumulated
depreciation of $140 million, which is included in the Company's rate base.
Output of NMP2 is shared in the same proportions as the cotenants' respective
ownership interests. The operating expenses of NMP2 are also allocated to the
cotenants in the same proportions as their respective ownership interests. The
Company's share of these expenses is included in the appropriate operating
expenses on its Statement of Income. The Company is required to provide its
respective share of financing for any capital additions to NMP2. Nuclear fuel
costs associated with NMP2 are being amortized on the basis of the quantity of
heat produced for the generation of electricity.
NMPC has contracted with the United States Department of Energy for the
disposal of nuclear fuel. The Company reimburses NMPC for its 18% share of the
cost under the contract at a rate of $1.00 per megawatt hour of net generation
less a factor to account for transmission line losses.
The Company's share of the decommissioning costs for NMP2 is estimated to be
$82 million and $234 million, in 1994 dollars and 2027 dollars, respectively,
based upon a 1989 study performed by NMPC which was updated in 1993 to reflect
a change in the NRC minimum decommissioning funding requirement. NMPC has
informed the Company that decommissioning costs for NMP2 will increase
primarily as a result of the inclusion of nuclear fuel storage charges and
costs for continuing care. NMPC will be performing an updated decommissioning
study for NMP2 in 1995. The Company will update its estimate for
decommissioning costs upon the NRC's approval of the 1995 study. NMPC expects
to commence decommissioning in 2027, shortly after cessation of operations,
using a method which removes or decontaminates NMP2 components promptly. The
Company's share of estimated decommissioning costs are being provided for in
electric rates and are being charged to operations as depreciation expense over
the expected service life of NMP2. The amount of decommissioning costs
recorded as depreciation expense in 1994 was $1.6 million. The accumulated
decommissioning costs collected in rates through December 31, 1994 amounted to
$8.7 million. The Company has established an independent decommissioning trust
fund for the decommissioning of the contaminated portion of the NMP2 plant,
which is approximately 92% of total decommissioning costs. As of December 31,
1994, the Company has accumulated $8.3 million in this external trust fund.
Net earnings on this fund are recorded as an increase to accumulated
depreciation. This fund complies with regulations issued by the NRC governing
the funding of nuclear plant decommissioning costs.
NOTE 6. CAPITAL STOCK
COMMON STOCK
During 1994, the Company issued 6.1 million shares of common stock, including
the public offering in June of 5.1 million shares at $20 per share. The
Company has 150,000,000 shares of authorized common stock, of which 118,416,606
were issued and outstanding at December 31, 1994. The Company has reserved
1,747,570 shares for sale through its Employee Stock Purchase Plan, 5,009,762
shares were committed to the Automatic Dividend Reinvestment Plan and 114,126
shares were reserved for conversion of the Series I Convertible Preferred Stock
at a rate of $17.15 per share. Common and preferred stock dividend limitations
in the mortgage securing the Company's First Mortgage Bonds are not material.
There are no dividend limitations contained in the Company's other debt
instruments.
PREFERRED STOCK
The Company has 7,000,000 authorized shares, cumulative preferred stock, par
value $100 per share and 30,000,000 authorized shares, cumulative preferred
stock, par value $25 per share. Dividends on preferred stock are paid in
preference to dividends on common stock or any other stock ranking junior to
preferred stock.
PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION
The aggregate fair value of redeemable preferred stock with mandatory
redemptions at December 31, 1994 and 1993 amounted to approximately $564
million and $659 million, respectively, compared to their carrying amounts of
$649 million and $654 million, respectively.
The Company is required to redeem each year certain series of preferred stock
through the operation of sinking fund provisions as follows:
[Download Table]
Number Redemption
Series Redemption Provision Beginning of Shares Price
------ ----------------------------------- --------- ----------
L July 31, 1979 10,500 $100
R December 15, 1982 37,500 100
NN March 1, 1999 77,700 25
UU October 15, 1999 112,000 25
In addition, the Company will have the non-cumulative option to double the
number of shares to be redeemed pursuant to the sinking fund provisions in any
year for the preferred stock series R, NN and UU. The aggregate par value of
preferred stock required to be redeemed through sinking funds in 1995 and 1996
is $4.8 million, in 1997 and 1998 is $1.1 million and in 1999 is $5.8 million.
The Company is also required to redeem all shares of certain series of
preferred stock which are not subject to sinking fund requirements. The
scheduled mandatory redemption for these series are as follows: (i) Series GG
on March 1, 1999; (ii) Series AA on June 1, 2000; (iii) Series QQ on May 1,
2001; and (iv) Series CC on August 1, 2002.
PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION
The Company has the option to redeem certain series of its preferred stock.
For the series subject to optional redemption at December 31, 1994, the call
prices were as follows:
[Download Table]
Preferred Stock Call Price
--------------- ----------
5.00% Series B $101
4.25% Series D 102
4.35% Series E 102
4.35% Series F 102
5 1/8% Series H 102
5 3/4% Series I - Convertible 100
PREFERENCE STOCK
At December 31, 1994, none of the authorized 7,500,000 shares of
nonparticipating preference stock, par value $1 per share, which ranks junior
to preferred stock, were outstanding.
NOTE 7. LONG-TERM DEBT
Each of the Company's outstanding mortgages is a lien on substantially all of
the Company's properties.
FIRST MORTGAGE
All of the bonds issued under the First Mortgage, including those issued after
June 1, 1975 and pledged with the Trustee of the General and Refunding Mortgage
(G&R Trustee) as additional security for General & Refunding Bonds (G&R Bonds),
are secured by the lien of the First Mortgage. First Mortgage Bonds pledged
with the G&R Trustee do not represent outstanding indebtedness of the Company.
Amounts of such pledged bonds outstanding were $1.3 billion and $1.0 billion at
December 31, 1994 and 1993, respectively. The annual First Mortgage
depreciation fund and sinking fund requirements for 1994, due not later than
June 30, 1995, are estimated at $239 million and $21 million, respectively.
The Company expects to meet these requirements with property additions and
retired First Mortgage Bonds.
G&R MORTGAGE
The lien of the G&R Mortgage is subordinate to the lien of the First Mortgage.
The annual G&R Mortgage sinking fund requirement for 1994, due not later than
June 30, 1995, is estimated at $26 million. The Company expects to satisfy
this requirement with retired G&R Bonds.
1989 REVOLVING CREDIT AGREEMENT
The Company has available through October 1, 1995, $300 million under its 1989
Revolving Credit Agreement (1989 RCA). This line of credit is secured by a
first lien upon the Company's accounts receivable and fuel oil inventories.
At December 31, 1994, no amounts were outstanding under the 1989 RCA. The
Company has the option, when amounts are outstanding, to commit to one of three
interest rates including: (i) the Adjusted Certificate of Deposit Rate which is
a rate based on the certificate of deposit rates of certain of the lending
banks, (ii) the Base Rate which is generally a rate based on Citibank, N.A.'s
prime rate and (iii) the Eurodollar Rate which is a rate based on the London
Interbank Offering Rate (LIBOR). The Company has agreed to pay a fee of one
quarter of one percent per annum on the unused portion. The 1989 RCA may be
extended for one year periods upon the acceptance by the lending banks of a
request by the Company which must be delivered to the lending banks prior to
April 1 of each year. It is the Company's intent to request an extension prior
to April 1, 1995.
AUTHORITY FINANCING NOTES
Authority Financing Notes are issued by the Company to the New York State
Energy Research and Development Authority (NYSERDA) to secure certain
tax-exempt Industrial Development Revenue Bonds, Pollution Control Revenue
Bonds (PCRBs) and Electric Facilities Revenue Bonds (EFRBs) issued by NYSERDA.
Certain of these bonds are subject to periodic tender at which time their
interest rates may be subject to redetermination. Tender requirements of
Authority Financing Notes at December 31, 1994 were as follows:
[Download Table]
(In thousands of dollars)
---------------------------------------------------------------------------------
Interest
Rate Series Principal
---------------------------------------------------------------------------------
PCRBs
8 1/4% 1982 $ 17,200 Tendered every three
years, next tender
October 1997
3.0% 1985 A,B 150,000 Tendered annually on
March 1
EFRBs
5.45% 1993 A 50,000 Tendered weekly
4.90% 1993 B 50,000 Tendered weekly
5.40% 1994 A 50,000 Tendered weekly
---------------------------------------------------------------------------------
The 1994 and 1993 EFRBs and the 1985 PCRBs are supported by letters of credit
pursuant to which the letter of credit banks have agreed to pay the principal,
interest and premium, if applicable, in the aggregate, up to approximately $326
million in the event of default. The obligation of the Company to reimburse
the letter of credit banks is unsecured. These letters of credit expire on
October 26, 1997 for the 1994 EFRBs, November 17, 1996 for the 1993 EFRBs, and
March 16, 1996 for the 1985 PCRBs, at each of which times the Company is
required to obtain either an extension of the letters of credit or substitute
credit backup. If neither can be obtained, the 1993 EFRBs, the 1994 EFRBs and
the 1985 PCRBs must be redeemed unless the Company purchases them in lieu of
redemption and subsequently remarkets them.
FAIR VALUES OF LONG-TERM DEBT
The carrying amounts and fair values of the Company's long-term debt at
December 31 were as follows:
[Download Table]
(In thousands of dollars)
-------------------------------------------------------------------------
1994
-------------------------------------------------------------------------
Fair Carrying
Value Amount
-------------------------------------------------------------------------
First Mortgage Bonds $ 95,688 $ 100,000
General and Refunding Bonds 1,844,289 1,951,000
Debentures 1,867,510 2,270,000
Authority Financing Notes 829,651 866,675
-------------------------------------------------------------------------
Total $4,637,138 $5,187,675
=========================================================================
[Download Table]
1993
-------------------------------------------------------------------------
Fair Carrying
Value Amount
-------------------------------------------------------------------------
First Mortgage Bonds $ 124,719 $ 125,000
General and Refunding Bonds 1,806,728 1,666,000
Debentures 2,944,499 2,880,058
Authority Financing Notes 851,800 816,675
-------------------------------------------------------------------------
Total $5,727,746 $5,487,733
=========================================================================
For a further discussion on the fair value of the securities listed above, see
Note 1.
MATURITY SCHEDULE
Total long-term debt maturing in each of the next five years is $25 million
(1995), $455 million (1996), $286 million (1997), $101 million (1998) and $454
million (1999).
NOTE 8. RETIREMENT BENEFIT PLANS
PENSION PLANS
The Company maintains a defined benefit pension plan which covers substantially
all employees (Primary Plan), a supplemental plan which covers officers and
certain key executives (Supplemental Plan) and a retirement plan which covers
the Board of Directors (Directors' Plan). The Company also maintains 401(k)
plans for its union and non-union employees. The Company does not contribute
to these plans.
Primary Plan
The Company's funding policy is to contribute annually to the Primary Plan a
minimum amount consistent with the requirements of the Employee Retirement
Income Security Act of 1974 (ERISA) plus such additional amounts, if any, as
the Company may determine to be appropriate from time to time.
For service before January 1, 1992, pension benefits are determined based on
the greater of the accrued benefit as of December 31, 1991, or by applying a
moving five year average of Plan compensation, not to exceed the January 1,
1992 salary, to certain percentages as defined in the Primary Plan, determined
by years of service at December 31, 1991. For service after January 1, 1992,
pension benefits are equal to 2% per year of Plan compensation through age 49
and 2 1/2% thereafter. Employees are vested in the Primary Plan after five
years of service with the Company.
The Primary Plan's funded status and amounts recognized on the Balance Sheet at
December 31, 1994 and 1993 were as follows:
[Enlarge/Download Table]
(In thousands of dollars)
-------------------------------------------------------------------------------------------------------
1994 1993
-------------------------------------------------------------------------------------------------------
Actuarial present value of benefit obligation
Vested benefits $ 467,962 $ 468,797
Nonvested benefits 50,385 49,815
-------------------------------------------------------------------------------------------------------
Accumulated Benefit Obligation $ 518,347 $ 518,612
=======================================================================================================
Plan assets at fair value $ 597,200 $ 598,600
Actuarial present value of projected
benefit obligation 592,339 597,128
-------------------------------------------------------------------------------------------------------
Projected benefit obligation less
than plan assets 4,861 1,472
Unrecognized net obligation 84,577 91,397
Unrecognized net gain (90,335) (97,029)
-------------------------------------------------------------------------------------------------------
Net Accrued Pension Cost $ (897) $ (4,160)
=======================================================================================================
Periodic pension cost for 1994, 1993 and 1992 for the Primary Plan included the
following components:
[Enlarge/Download Table]
(In thousands of dollars)
-------------------------------------------------------------------------------------------------------
1994 1993 1992
-------------------------------------------------------------------------------------------------------
Service cost - benefits earned during the period $ 16,465 $ 14,481 $ 13,661
Interest cost on projected benefit
obligation and service cost 43,782 41,865 39,574
Actual return on plan assets (12,431) (54,010) (47,156)
Net amortization and deferral (31,633) 10,025 12,849
-------------------------------------------------------------------------------------------------------
Net Periodic Pension Cost $ 16,183 $ 12,361 $ 18,928
=======================================================================================================
[Enlarge/Download Table]
Assumptions used in accounting for the Primary Plan were as follows:
-------------------------------------------------------------------------------------------------------
1994 1993 1992
-------------------------------------------------------------------------------------------------------
Discount rate 7.75% 7.25% 7.75%
Rate of future compensation increases 5.0 % 5.0 % 5.5 %
Long-term rate of return on assets 7.5 % 7.5 % 7.5 %
-------------------------------------------------------------------------------------------------------
The Primary Plan assets at fair value include cash, cash equivalents, group
annuity contracts, bonds and listed equity securities.
In 1993 the PSC issued an order which addressed the accounting and ratemaking
treatment of pension costs in accordance with SFAS No. 87, Employers'
Accounting for Pensions. Under the PSC order, the Company is required to
recognize any deferred net gains or losses over a ten year period rather than
using the corridor approach method. This change in the annual pension cost
calculation reduced pension expense by $4.6 million in the year of adoption,
1993. The Company believes that this method of accounting for financial
reporting purposes, results in a better matching of revenues and the Company's
pension cost. The Company defers differences between pension rate allowance
and pension expense under the PSC's order. In addition, the PSC requires the
Company to measure the difference between the pension rate allowance and the
annual pension contributions contributed into the pension fund.
Supplemental Plan
The Supplemental Plan, the cost of which is borne by the Company's shareowners,
provides supplemental death and retirement benefits for officers and other key
executives without contribution from such employees. The Supplemental Plan is
a non-qualified plan under the Internal Revenue Code. Death benefits are
currently provided by insurance. The provision for plan benefits, which is
unfunded, totaled approximately $2.3 million, $2.8 million and $.7 million
which was recognized as expense in 1994, 1993 and 1992, respectively.
Directors' Plan
The Directors' Plan provides benefits to directors who are not officers of the
Company. Directors who have served in that capacity for more than five years
qualify as participants under the plan. The Directors' Plan is a non-qualified
plan under the Internal Revenue Code. The provision for retirement benefits,
which is unfunded, totaled approximately $148,000, $150,000, and $133,000 which
was recognized as expense in 1994, 1993 and 1992, respectively.
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
In addition to providing pension benefits, the Company provides certain medical
and life insurance benefits for retired employees. Substantially all of the
Company's employees may become eligible for these benefits if they reach
retirement age after working for the Company for a minimum of five years.
These and similar benefits for active employees are provided by the Company or
by insurance companies whose premiums are based on the benefits paid during the
year. Effective January 1, 1993, the Company adopted the provisions of SFAS
No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions,
which requires the Company to recognize the expected cost of providing
postretirement benefits when employee services are rendered rather than when
paid. As a result, the Company, in 1993, recorded an accumulated
postretirement benefit obligation and a corresponding regulatory asset of
approximately $376 million. Additionally, as a result of adopting SFAS No.
106, the Company's postretirement benefit cost for 1993 increased by
approximately $28 million above the amount that would have been recorded under
the pay-as-you-go method.
In 1993, the PSC issued an order which required that the effects of
implementing SFAS No. 106 be phased into rates. The order requires the Company
to defer as a regulatory asset the difference between postretirement benefit
expense recorded for accounting purposes in accordance with SFAS No. 106 and
the postretirement benefit expense reflected in rates. The ongoing annual
postretirement benefit expense will be phased into and fully reflected in rates
within a five year period with the accumulated postretirement obligation being
recovered in rates over a twenty year period. In addition, the Company is
required to recognize any deferred net gains or losses over a ten year period.
In 1994, the Company established Voluntary Employee's Beneficiary Association
(VEBA) trusts for union and non-union employees for the funding of incremental
costs collected in rates for postretirement benefits. In December 1994, the
Company contributed $2.2 million for the incremental postretirement benefit
cost collected in gas rates. In 1995, the Company will begin funding the
incremental postretirement benefit cost for the electric business as these
amounts are reflected in rates.
Accumulated postretirement benefit obligation other than pensions at December
31 were as follows:
[Download Table]
(In thousands of dollars)
---------------------------------------------------------------------------------
1994 1993
--------------------------------------------------------------------------------
Retirees $ 159,590 $ 152,800
Fully eligible plan participants 57,788 63,800
Other active plan participants 133,030 137,200
--------------------------------------------------------------------------------
Accumulated postretirement
benefit obligation $ 350,408 $ 353,800
Plan assets, cash (2,200) -
--------------------------------------------------------------------------------
Accumulated postretirement benefit
obligation in excess of plan
assets 348,208 353,800
Unrecognized net gain 73,936 49,237
--------------------------------------------------------------------------------
Accrued Postretirement Benefit Cost $ 422,144 $ 403,037
================================================================================
Periodic postretirement benefit cost other than pensions for the years 1994,
1993 and 1992 were as follows:
[Download Table]
1994 1993 1992
--------------------------------------------------------------------------------
Service cost - benefits
earned during the period $ 11,275 $ 12,980 $ -
Interest cost on projected
benefit obligation and
service cost 25,713 29,531 -
Amortization of net gain (5,213) - -
--------- --------- ---------
Periodic Postretirement
Benefit Cost $ 31,775 $ 42,511 $ 13,400
========= ========= =========
Assumptions used to determine the postretirement benefit obligation were as
follows:
[Download Table]
1994 1993
------------------
Discount rate 7.75% 7.25%
Rate of future compensation
increases 5.0% 5.0%
The assumed health care cost trend rates used in measuring the accumulated
postretirement benefit obligation at December 31, 1994 and 1993 were 9.0% and
9.5%, respectively, gradually declining to 6.0% in 2001 and thereafter. A one
percentage point increase in the health care cost trend rate would increase the
accumulated postretirement benefit obligation as of December 31, 1994 and 1993
by approximately $44 million and $46 million, respectively, and the sum of the
service and interest costs in 1994 and 1993 by $6 and $8 million, respectively.
NOTE 9. FEDERAL INCOME TAX
At December 31, the significant components of the Company's deferred tax assets
and liabilities calculated under the provisions of SFAS No. 109 were as
follows:
[Download Table]
(In thousands of dollars)
---------------------------------------------------------------------------------
1994 1993
---------------------------------------------------------------------------------
DEFERRED TAX ASSETS
Net operating loss carryforwards $ 552,917 $ 707,400
Reserves not currently deductible 86,267 87,050
Tax depreciable basis in excess of book 48,557 59,147
Nondiscretionary excess credits 31,933 35,362
ITC carryforwards 142,329 142,329
Other 89,763 62,800
---------------------------------------------------------------------------------
Total Deferred Tax Assets $ 951,766 $1,094,088
---------------------------------------------------------------------------------
DEFERRED TAX LIABILITIES
1989 Settlement $ 2,174,729 $2,180,413
Accelerated depreciation 608,302 597,827
Call premiums 56,324 63,735
Rate case deferrals 55,598 43,957
Other 46,840 46,097
---------------------------------------------------------------------------------
Total Deferred Tax Liabilities 2,941,793 2,932,029
---------------------------------------------------------------------------------
Net Deferred Tax Liability $1,990,027 $1,837,941
=================================================================================
Federal income tax expense in accordance with APB No. 11, for the year 1992 was
as follows:
[Download Table]
(In thousands of dollars)
---------------------------------------------------------------------------------
1992
---------------------------------------------------------------------------------
FEDERAL INCOME TAX, PER STATEMENT
OF INCOME
Current $ 530
---------------------------------------------------------------------------------
Deferred and other
1989 Settlement
Shoreham property 3,806
Rate moderation component 10,351
Other 1989 Settlement items 8,622
Net operating loss carryforwards (14,121)
Shoreham post settlement costs 60,125
Accelerated tax depreciation 35,951
Call premiums 35,441
Ratemaking and performance plan 17,680
Other items 2,577
---------------------------------------------------------------------------------
Total Deferred and Other 160,432
---------------------------------------------------------------------------------
TOTAL FEDERAL INCOME TAX EXPENSE $ 160,962
=================================================================================
The federal income tax amounts included in the Statement of Income differ from
the amounts which result from applying the statutory federal income tax rate to
income before income tax. The table below sets forth the reasons for such
differences.
[Download Table]
(In thousands of dollars)
---------------------------------------------------------------------------------
1994 1993 1992
---------------------------------------------------------------------------------
Income before federal income tax $ 478,564 $ 468,839 $ 462,936
Statutory federal income tax rate 35% 35% 34%
---------------------------------------------------------------------------------
Statutory federal income tax $ 167,497 $ 164,094 $ 157,398
Additions (reductions) in federal
income tax
1989 Settlement 4,213 4,256 4,003
Allowance for funds used during
construction (2,450) (2,304) (4,118)
Tax credits (6,837) (6,871) (6,586)
Excess of book depreciation over
tax depreciation 14,745 12,437 12,193
Interest capitalized 2,449 3,443 2,947
Other items (2,905) (2,779) (4,875)
---------------------------------------------------------------------------------
Total Federal Income Tax Expense $ 176,712 $ 172,276 $ 160,962
=================================================================================
Effective federal income tax rate 36.9% 36.7% 34.8%
The Company's net operating loss (NOL) carryforwards for federal income tax
purposes is estimated to be approximately $1.6 billion at December 31, 1994.
The NOL will expire in the years 2004 through 2007. The amount of investment
tax credit (ITC) carryforwards, net of the 35% reduction required by the Tax
Reform Act of 1986, are approximately $142 million. The ITC carryforwards
expire by the year 2005. For financial reporting purposes, a valuation
allowance was not required to offset the deferred tax assets related to these
carryforwards.
On January 8, 1990 and October 10, 1992, the Company received Revenue Agents'
Reports disallowing certain deductions claimed by the Company on its tax
returns for the audit cycle years 1984-1987 and 1988-1989, respectively. The
Revenue Agents' Reports reflect proposed adjustments to the Company's federal
income tax returns for 1984 through 1989 which, if sustained, would give rise
to tax deficiencies totaling approximately $220 million. The Revenue Agents
have proposed ITC adjustments which, if sustained, would reduce the Company's
ITC carryforwards by approximately $96 million. The Company is protesting some
of the adjustments and is seeking an administrative and, if necessary, a
judicial review of the conclusions reached in the Revenue Agents' Reports. The
Company cannot predict either the timing or the manner in which these matters
will be resolved. If however, the ultimate disposition of any or all matters
raised in the Revenue Agents' Reports are adverse to the Company, the Company
expects that any deficiencies that may arise will be substantially offset by
the net operating loss carrybacks associated with the 1989 Shoreham abandonment
loss deduction of $1.8 billion and thus any impact would not have a material
effect on the Company's financial condition or cash flows.
NOTE 10. COMMITMENTS AND CONTINGENCIES
COMMITMENTS
The Company has entered into substantial commitments for gas supply, purchased
power and transmission facilities. The costs associated with these commitments
are recovered from ratepayers through provisions in the Company's rate
schedules.
The Company expects that it will have to expend approximately $1 million in
1995 to meet continuous emission monitoring requirements and to meet Phase I
nitrogen oxide (NOx) reduction requirements. Subject to requirements that are
expected to be promulgated in forthcoming regulations, the Company estimates
that it may be required to expend approximately $80 million (net of NOx credit
sales) by 2003 to meet Phase II and Phase III NOx reduction requirements and
approximately $24 million by 1999 to meet potential requirements for the
control of hazardous air pollutants from power plants. The Company believes
that all of the above costs will be recoverable through rates.
CONTINGENCIES
Environmental Matters
The Company is subject to federal, State and local laws and regulations dealing
with air and water quality and other environmental matters. The Company
continually monitors its activities in order to determine the impact of such
activities on the environment and to ensure compliance with various
environmental laws. Except as set forth below, no material proceedings have
been commenced or, to the knowledge of the Company, are contemplated against
the Company with respect to any matter relating to the protection of the
environment.
The New York State Department of Environmental Conservation has indicated to
New York State utilities that it may require all such utilities to investigate
and, where necessary, remediate their former manufactured gas plant (MGP)
sites. The Company is the owner of six pieces of property on which the Company
or certain of its predecessor companies produced manufactured gas. Although
the exact amount of the Company's clean-up costs cannot yet be determined,
based on the findings of investigations at two of these six sites, preliminary
estimates indicate that it will cost approximately $35 million to clean up all
of these sites over the next five to ten years. Accordingly, the Company has
recorded a $35 million liability and has also recorded a $35 million regulatory
asset to reflect its belief that the PSC will provide for the future recovery
of these costs through rates as it has for other New York State utilities. The
Company has notified its former and current insurance carriers that it seeks to
recover from them certain of these clean-up costs. However, the Company is
unable to predict the amount of insurance recovery, if any, that it may obtain.
The Company has been notified by the Environmental Protection Agency (EPA) that
it is one of many potentially responsible parties (PRPs) that may be liable for
the remediation of three contaminated licensed treatment, storage and disposal
sites. At one site, located in Philadelphia, Pennsylvania, and operated by
Metal Bank of America, the Company and nine other PRPs, all of which are public
utilities, have completed a Remedial Investigation and Feasibility Study which
is currently being reviewed by the EPA. The level of remediation required will
be determined when the EPA issues its decision, currently expected in May 1995.
The Company currently anticipates that the total cost to remediate this site
will be between $14 million and $30 million. The Company has recorded a
liability of $1.1 million representing its estimated share of the cost to
remediate this site. The Company believes that any cost incurred to remediate
this site will be recoverable through rates.
With respect to the other two sites, located in Kansas City, Kansas and Kansas
City, Missouri, the Company is investigating allegations that it had previously
stored or made agreements for disposal of polychlorinated biphenyls (PCBs) or
items containing PCBs at these sites. The Company is currently unable to
determine its share of the cost to remediate these two sites or the impact, if
any, on the Company's financial position. The Company believes that any cost
incurred to remediate these sites will be recoverable through rates.
As a result of its daily business activity, the Company is involved in various
legal and administrative proceedings, including other environmental
proceedings. The Company believes the resolution of these proceedings will not
have a material adverse effect on the Company's financial position or results
of operations.
NUCLEAR PLANT INSURANCE
The NRC requires the owners of nuclear facilities to maintain certain types of
insurance. For property damage at each nuclear generating site, the NRC
requires a minimum of $1.06 billion of coverage. The NRC has provided the
Company with a partial exemption from these requirements for Shoreham. With
respect to third party liability and property damage, the NRC requires nuclear
plant owners to carry $200 million in primary coverage. Pursuant to these
requirements, the Company carries property insurance and third party bodily
injury and property liability insurance for its 18% share in NMP2 and for
Shoreham. The annual premiums for this coverage are not material.
The policies also include retroactive premiums under certain circumstances.
For the property damage policies, the retroactive premium assessments, on a per
occurrence basis, could be as much as $4.6 million. Once Shoreham is declared
a non-nuclear site by the NRC this retroactive premium assessment may decrease
significantly.
For the third party liability and property damage insurance, the retroactive
premium is related to the NRC's requirement that nuclear facility owners, in
addition to carrying $200 million in primary coverage, also participate in a
Secondary Financial Protection Fund (Fund). Under the Price Anderson Act, that
assessment related to the Fund could be up to $79.3 million per nuclear
incident in any one year at any nuclear unit, but not in excess of $10 million
in payments per year for each incident. The Price Anderson Act also limits
liability for third-party bodily injury and third-party property damage arising
out of a nuclear occurrence at each unit to $8.9 billion.
In 1994, the NRC granted the Company permission to withdraw from the Fund
because Shoreham had been defueled. The withdrawal was effective November 18,
1994. The withdrawal relieves the Company from any retroactive premium
assessment relating to any nuclear incident as of November 18, 1994 or later.
The Company remains liable for retroactive assessments for any nuclear incident
occurring prior to November 18, 1994 during the time the Company participated
in the Fund because of its Shoreham ownership. The likelihood that the
Company's retroactive premium responsibility would be triggered, however, is
remote since it is highly unlikely that a nuclear unit had a nuclear incident
prior to November 18, 1994, did not report the incident, and that incident is
significant enough to exceed the primary coverage of $200 million, thus
triggering the retroactive premium provisions. As a co-owner of NMP2, the
Company remains liable for 18% of any retroactive premium assessment levied
against the NMP2 owners.
NOTE 11. SEGMENTS OF BUSINESS
The Company is engaged in the electric and natural gas utility businesses. The
Company serves residential, commercial and industrial customers in Nassau and
Suffolk Counties and the Rockaway Peninsula in Queens County, all on Long
Island, New York. Identifiable assets by segment include net utility plant,
regulatory assets, materials and supplies, accrued unbilled revenues, gas in
storage, fuel and deferred charges. Assets utilized for overall Company
operations consist primarily of cash and cash equivalents, accounts receivable
and unamortized cost of issuing securities.
[Enlarge/Download Table]
(In millions of dollars)
------------------------------------------------------------------------------------------------------------------
For year ended December 31 1994 1993 1992
------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES
Electric $ 2,481 $ 2,352 $ 2,195
Gas 586 529 427
------------------------------------------------------------------------------------------------------------------
Total $ 3,067 $ 2,881 $ 2,622
==================================================================================================================
OPERATING EXPENSES (EXCLUDES FEDERAL INCOME TAX)
Electric $ 1,640 $ 1,514 $ 1,355
Gas 501 427 353
------------------------------------------------------------------------------------------------------------------
Total $ 2,140 $ 1,941 1,708
==================================================================================================================
OPERATING INCOME (BEFORE FEDERAL INCOME TAX)
Electric $ 842 $ 838 $ 840
Gas 85 102 74
------------------------------------------------------------------------------------------------------------------
Total operating income 927 940 914
AFC (7) (7) (12)
Other income and deductions (45) (56) (50)
Interest charges 500 534 513
Federal income tax 177 172 161
------------------------------------------------------------------------------------------------------------------
Net Income $ 302 $ 297 $ 302
==================================================================================================================
DEPRECIATION AND AMORTIZATION
Electric $ 112 $ 106 $ 104
Gas 19 16 15
------------------------------------------------------------------------------------------------------------------
Total $ 131 $ 122 $ 119
==================================================================================================================
CONSTRUCTION AND NUCLEAR FUEL EXPENDITURES*
Electric $ 155 $ 171 $ 164
Gas 125 134 109
------------------------------------------------------------------------------------------------------------------
Total $ 280 $ 305 $ 273
==================================================================================================================
*Includes non-cash allowance for other funds used during construction and
excludes Shoreham
post settlement costs.
[Enlarge/Download Table]
(In millions of dollars)
------------------------------------------------------------------------------------------------------------------
At December 31 1994 1993 1992
------------------------------------------------------------------------------------------------------------------
IDENTIFIABLE ASSETS
Electric $ 10,999 $ 11,194 $ 8,867
Gas 1,184 1,078 768
Total identifiable assets 12,183 12,272 9,635
Assets utilized for overall Company operations 1,034 1,121 1,129
------------------------------------------------------------------------------------------------------------------
Total Assets $ 13,217 $ 13,393 $ 10,764
------------------------------------------------------------------------------------------------------------------
NOTE 12. QUARTERLY FINANCIAL INFORMATION
(Unaudited)
[Enlarge/Download Table]
(In thousands of dollars except earnings per common share)
-----------------------------------------------------------------------------------------------------------------------
1994 1993
-----------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES
For the quarter ended March 31 $ 872,143 $ 760,451
June 30 626,310 604,871
September 30 913,440 849,700
December 31 655,414 665,973
-----------------------------------------------------------------------------------------------------------------------
OPERATING INCOME
For the quarter ended March 31 $ 183,865 $ 192,391
June 30 139,478 167,599
September 30 276,965 263,984
December 31 144,637 131,577
-----------------------------------------------------------------------------------------------------------------------
NET INCOME
For the quarter ended March 31 $ 69,620 $ 67,861
June 30 24,787 56,806
September 30 168,872 144,549
December 31 38,573 27,347
-----------------------------------------------------------------------------------------------------------------------
EARNINGS FOR COMMON STOCK
For the quarter ended March 31 $ 56,348 $ 53,286
June 30 11,516 42,451
September 30 155,620 131,022
December 31 25,348 13,696
-----------------------------------------------------------------------------------------------------------------------
EARNINGS PER COMMON SHARE
For the quarter ended March 31 $ .50 $ .48
June 30 .10 .38
September 30 1.32 1.17
December 31 .21 .12
-----------------------------------------------------------------------------------------------------------------------
In the fourth quarter of 1993, the Company recorded income of approximately
$6.5 million, net of tax effects, or $.06 per common share related to the
settlement of certain litigation. In addition, in the fourth quarter of 1993,
the Company recorded a charge to earnings of approximately $7.3 million, net of
tax effects or $.07 per common share principally related to previously deferred
storm costs and the reconciliation of certain ratemaking mechanisms recorded in
connection with the conclusion of the Company's rate year.
REPORT OF ERNST & YOUNG LLP, INDEPENDENT AUDITORS
To the Shareowners and Board of Directors of Long Island Lighting Company
We have audited the accompanying balance sheet of Long Island Lighting Company
and the related statement of capitalization as of December 31, 1994 and 1993
and the related statements of income, retained earnings and cash flows for each
of the three years in the period ended December 31, 1994. Our audits also
included the financial statement schedule listed in the Index at Item 14(a).
These financial statements and schedule are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements and schedule based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. 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 Long Island Lighting Company
at December 31, 1994 and 1993, and the results of its operations and its cash
flows for each of the three years in the period ended December 31, 1994, in
conformity with generally accepted accounting principles. Also, in our
opinion, the related financial statement schedule, when considered in relation
to the basic financial statements taken as a whole, presents fairly in all
material respects the information set forth therein.
/s/ Ernst & Young LLP
Melville, New York
February 3, 1995
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
Not applicable.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY
Information required by Item 10 as to the Company's Executive
Officers is set forth in Item 1, "Business" under the heading "Executive
Officers of the Company" above. Information required by Item 10 as to the
Company's Directors may be found in the Company's proxy statement for its
annual meeting to be held on May 24, 1995 (the "Annual Meeting"). Such proxy
statement is incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION
Information required by Item 11 may be found in the Company's
proxy statement for the Annual Meeting. Such proxy statement is incorporated
herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Information required by Item 12 may be found in the Company's
proxy statement for the Annual Meeting. Such proxy statement is incorporated
herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information required by Item 13 may be found in the Company's
proxy statement for the Annual Meeting. Such proxy statement is incorporated
herein by reference.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM
8-K
(a)(1) List of Financial Statements
Statement of Income for each of the three years in the period
ended December 31, 1994.
Balance Sheet at December 31, 1994 and 1993.
Statement of Retained Earnings for each of the three years
in the period ended December 31, 1994.
Statement of Capitalization at December 31, 1994 and 1993.
Statement of Cash Flows for each of the three years in the
period ended December 31, 1994.
Notes to Financial Statements.
(2) List of Financial Statement Schedules
Valuation and Qualifying Accounts (Schedule II)
(3) List of Exhibits
Exhibits listed below which have been filed with the Securities and Exchange
Commission pursuant to the Securities Act of 1933 or the Securities Exchange
Act of 1934, and which were filed as noted below, are hereby incorporated by
reference and made a part of this report with the same effect as if filed
herewith.
3(a) Restated Certificate of Incorporation of the Company dated November
11, 1993 (filed as an Exhibit to the Company's Form 10-K for the Year
Ended December 31, 1993.)
(b) By-laws of the Company as amended on May 28, 1991 (filed as an Exhibit
to the Company's Form 10-K for the Year Ended December 31, 1991.)
4(a) General and Refunding Indenture dated as of June 1, 1975 (filed as an
Exhibit to the Company's Form 10-K for the Year Ended December 31,
1991.)
Twenty-seven Supplemental Indentures to the General and Refunding
Indenture dated as of June 1, 1975, as follows:
[Download Table]
Previously Filed As An
Supplemental Indenture Exhibit To The Company's
Number Date Form Date
------ ---- ---- ----
First 06/1/75 10-K 12/31/87
Second 09/1/75 10-K 12/31/87
Third 06/1/76 10-K 12/31/87
Fourth 12/1/76 10-K 12/31/87
Fifth 05/1/77 10-K 12/31/87
Sixth 04/1/78 10-K 12/31/87
Seventh 03/1/79 10-K 12/31/87
Eighth 02/1/80 10-K 12/31/87
Ninth 03/1/81 10-K 12/31/87
Tenth 07/1/81 10-K 12/31/87
Eleventh 07/1/81 10-K 12/31/87
Twelfth 12/1/81 10-K 12/31/87
Thirteenth 12/1/81 10-K 12/31/87
Fourteenth 06/1/82 10-K 12/31/87
Fifteenth 10/1/82 10-K 12/31/87
Sixteenth 04/1/83 10-K 12/31/87
Seventeenth 05/1/83 10-K 12/31/87
Eighteenth 09/1/84 10-K 12/31/87
Nineteenth 10/1/84 10-K 12/31/87
Twentieth 06/1/85 10-K 12/31/87
Twenty-first 04/1/86 10-K 12/31/87
Twenty-second 02/1/91 10-K 12/31/90
Twenty-third 05/1/91 10-K 12/31/91
Twenty-fourth 07/1/91 10-K 12/31/91
[Download Table]
Twenty-fifth 05/1/92 10-K 12/31/92
Twenty-sixth 07/1/92 10-K 12/31/92
*Twenty-seventh 06/1/94 10-K 12/31/94
4(b) Indenture of Mortgage and Deed of Trust dated as of September 1, 1951
(filed as an Exhibit to the Company's Form 10-K for the Year Ended
December 31, 1987.)
Fifty Supplemental Indentures to the Indenture of Mortgage and Deed of
Trust dated as of September 1, 1951, as follows:
[Download Table]
Previously Filed As An
Supplemental Indenture Exhibit To The Company's
Number Date Form Date
------ ---- ---- ----
First 12/1/51 10-K 12/31/87
Second 10/1/52 10-K 12/31/87
Third 09/1/53 10-K 12/31/87
Fourth 12/1/54 10-K 12/31/87
Fifth 11/1/55 10-K 12/31/87
Sixth 12/1/56 10-K 12/31/87
Seventh 05/1/58 10-K 12/31/87
Eighth 07/1/59 10-K 12/31/87
Ninth 08/1/61 10-K 12/31/87
Tenth 04/1/63 10-K 12/31/87
Eleventh 06/1/64 10-K 12/31/87
Twelfth 06/1/65 10-K 12/31/87
Thirteenth 03/1/66 10-K 12/31/87
Fourteenth 04/1/67 10-K 12/31/87
Fifteenth 09/1/69 10-K 12/31/87
Sixteenth 09/1/70 10-K 12/31/87
Seventeenth 04/1/71 10-K 12/31/87
Eighteenth 12/1/71 10-K 12/31/87
Nineteenth 09/1/72 10-K 12/31/87
Twentieth 12/1/73 10-K 12/31/87
Twenty-first 06/1/74 10-K 12/31/87
Twenty-second 11/1/74 10-K 12/31/87
Twenty-third 06/1/75 10-K 12/31/87
Twenty-fourth 09/1/75 10-K 12/31/87
Twenty-fifth 06/1/76 10-K 12/31/87
Twenty-sixth 12/1/76 10-K 12/31/87
Twenty-seventh 05/1/77 10-K 12/31/87
Twenty-eighth 04/1/78 10-K 12/31/87
Twenty-ninth 03/1/79 10-K 12/31/87
Thirtieth 02/1/80 10-K 12/31/87
Thirty-first 03/1/81 10-K 12/31/87
Thirty-second 07/1/81 10-K 12/31/87
Thirty-third 07/1/81 10-K 12/31/87
Thirty-fourth 12/1/81 10-K 12/31/87
__________________________________
*Filed herewith.
[Download Table]
Thirty-fifth 12/1/81 10-K 12/31/87
Thirty-sixth 06/1/82 10-K 12/31/87
Thirty-seventh 10/1/82 10-K 12/31/87
Thirty-eighth 04/1/83 10-K 12/31/87
Thirty-ninth 05/1/83 10-K 12/31/87
Fortieth 02/29/84 10-K 12/31/87
Forty-first 09/1/84 10-K 12/31/87
Forty-second 10/1/84 10-K 12/31/87
Forty-third 06/1/85 10-K 12/31/87
Forty-fourth 04/1/86 10-K 12/31/87
Forty-fifth 02/1/91 10-K 12/31/90
Forty-sixth 05/1/91 10-K 12/31/91
Forty-seventh 07/1/91 10-K 12/31/91
Forty-eighth 05/1/92 10-K 12/31/92
Forty-ninth 07/1/92 10-K 12/31/92
*Fiftieth 06/1/94 10-K 12/31/94
4(c) Debenture Indenture dated as of November 1, 1986 from the Company to
The Connecticut Bank and Trust Company, National Association, as
Trustee (filed as an Exhibit to the Company's Form 10-K for the Year
Ended December 31, 1986).
Seven Supplemental Indentures to the Debenture Indenture dated as of
November 1, 1986, filed as follows:
[Download Table]
Previously Filed As An
Supplemental Indenture Exhibit To The Company's
Number Date Form Date
------ ---- ---- ----
First 11/1/86 10-K 12/31/86
Second 04/1/86 10-K 12/31/89
Third 07/1/86 10-K 12/31/89
Fourth 07/1/92 10-K 12/31/92
Fifth 11/1/92 10-K 12/31/92
Sixth 06/1/93 10-K 12/31/92
Seventh 07/1/93 10-K 12/31/92
__________________________________
*Filed herewith.
4(d) Debenture Indenture dated as of November 1, 1992 from the Company to
Chemical Bank, as Trustee (filed as an Exhibit to the Company's Form
10-K for the Year Ended December 31, 1992).
Four Supplemental Indentures to the Debenture Indenture dated as of
November 1, 1992, filed as follows:
[Download Table]
Previously Filed As An
Supplemental Indenture Exhibit To The Company's
Number Date Form Date
------ ---- ---- ----
First 01/1/93 10-K 12/31/92
Second 03/1/93 10-K 12/31/92
Third 03/1/93 10-K 12/31/92
Fourth 03/1/93 10-K 12/31/92
10(a) Sound Cable Project Facilities and Marketing Agreement dated as of
August 26, 1987 between the Company and the Power Authority of the
State of New York (filed as an Exhibit to the Company's Form 10-K for
the Year Ended December 31, 1987).
10(b) Transmission Agreement by and between the Company and Consolidated
Edison Company of New York, Inc. dated as of March 31, 1989 (filed as
an Exhibit to the Company's Form 10-K for the Year Ended December 31,
1989).
10(c) Contract for the sale of Firm Power and Energy by and between the
Company and the State of New York dated as of April 26, 1989 (filed as
an Exhibit to the Company's Form 10-K for the Year Ended December 31,
1989).
10(d) Capacity Supply Agreement dated as of December 13, 1991 between the
Company and the Power Authority of the State of New York (filed as an
Exhibit to the Company's Form 10-K for the Year Ended December 31,
1991).
10(e) Nine Mile Point Nuclear Station Unit 2 Operating Agreement dated as of
January 1, 1993 by and between the Company, New York State Electric &
Gas Corporation, Rochester Gas and Electric Corporation and Central
Hudson Gas and Electric Corporation (filed as an Exhibit to the
Company's Form 10-K for the Year Ended December 31, 1993).
10(f) Settlement Agreement on Issues Related to Nine Mile Two Nuclear Plant
dated as of June 6, 1990 by and between the Company, the Staff of the
Department of Public Service and others (filed as an Exhibit to the
Company's Form 10-K for the Year Ended December 31, 1990).
10(g) Settlement Agreement -- LILCO Issues dated as of February 28, 1989 by
and between the Company and the State of New York (filed as an Exhibit
to the Company's Form 10-K for the Year Ended December 31, 1988).
10(h) Amended and Restated Asset Transfer Agreement by and between the
Company and the Long Island Power Authority dated as of June 16, 1988
as amended and restated on April 14, 1989 (filed as an Exhibit to the
Company's Form 10-K for the Year Ended December 31, 1989).
10(i) Memorandum of Understanding concerning proposed agreements on power
supply for Long Island dated as of June 16, 1988 by and between the
Company and New York Power Authority as amended May 24, 1989 (filed as
an Exhibit to the Company's Form 10-K for the Year Ended December 31,
1989).
10(j) Rate Moderation Agreement submitted by the staff of the New York
State Public Service Commission on March 16, 1989 and supported by the
Company (filed as an Exhibit to the Company's Form 10-K for the Year
Ended December 31, 1989).
10(k) Site Cooperation and Reimbursement Agreement dated as of January 24,
1990 by and between the Company and Long Island Power Authority (filed
as an Exhibit to the Company's Form 10-K for the Year Ended December
31, 1989).
10(l) Stipulation of settlement of federal Racketeer Influenced and Corrupt
Organizations Act Class Action and False Claims Action dated as of
February 27, 1989 among the attorneys for the Company, the ratepayer
class, the United States of America and the individual defendants
named therein (filed as an Exhibit to the Company's Form 10-K for the
Year Ended December 31, 1988).
10(m) Revolving Credit Agreement dated as of June 27, 1989, between the
Company and the banks and co-agents listed therein, with the Exhibits
thereto (filed as an Exhibit to the Company's Form 10-K for the Year
Ended December 31, 1989) and as amended by the First Amendment dated
as of October 13, 1989 (filed as an Exhibit to the Company's Form 10-K
for the Year Ended December 31, 1990) and as amended by the Second
Amendment dated as of March 5, 1992 and as modified by a Waiver dated
November 5, 1992 (filed as an Exhibit to the Company's Form 10-K for
the Year Ended December 31, 1992).
10(n) Indenture of Trust dated as of December 1, 1989 by and between New
York State Energy Research and Development Authority ("NYSERDA") and
The Connecticut National Bank, as Trustee, relating to the 1989 EFRBs
(filed as an Exhibit to the Company's Form 10-K for the Year Ended
December 31, 1989).
Participation Agreement dated as of December 1, 1989 by and between
NYSERDA and the Company relating to the 1989 EFRBs (filed as an
Exhibit to the Company's Form 10-K for the Year Ended December 31,
1989).
10(o) Indenture of Trust dated as of May 1, 1990 by and between NYSERDA and
The Connecticut National Bank, as Trustee, relating to the 1990 EFRBs
(filed as an Exhibit to the Company's Form 10-K for the Year Ended
December 31, 1990).
Participation Agreement dated as of May 1, 1990 by and between NYSERDA
and the Company relating to the 1990 EFRBs (filed as an Exhibit to the
Company's Form 10-K for the Year Ended December 31, 1990).
10(p) Indenture of Trust dated as of January 1, 1991 by and between NYSERDA
and The Connecticut National Bank, as Trustee, relating to the 1991
EFRBs (filed as an Exhibit to the Company's Form 10-K for the Year
Ended December 31, 1990).
Participation Agreement dated as of January 1, 1991 by and between
NYSERDA and the Company relating to the 1991 EFRBs (filed as an
Exhibit to the Company's Form 10-K for the Year Ended December 31,
1990).
10(q) Indenture of Trust dated as of February 1, 1992 by and between NYSERDA
and IBJ Schroder Bank and Trust Company, as Trustee, relating to the
1992 EFRBs, Series A (filed as an Exhibit to the Company's Form 10-K
for the Year Ended December 31, 1991).
Participation Agreement dated as of February 1, 1992 by and between
NYSERDA and the Company relating to the 1992 EFRBs, Series A (filed as
an Exhibit to the Company's Form 10-K for the Year Ended December 31,
1991).
10(r) Indenture of Trust dated as of February 1, 1992 by and between NYSERDA
and IBJ Schroder Bank and Trust Company, as Trustee, relating to the
1992 EFRBs, Series B (filed as an Exhibit to the Company's Form 10-K
for the Year Ended December 31, 1991).
Participation Agreement dated as of February 1, 1992 by and between
NYSERDA and the Company relating to the 1992 EFRBs, Series B (filed as
an Exhibit to the Company's Form 10-K for the Year Ended December 31,
1991).
10(s) Indenture of Trust dated as of August 1, 1992 by and between NYSERDA
and IBJ Schroder Bank and Trust Company, as Trustee, relating to the
1992 EFRBs, Series C (filed as an Exhibit to the Company's Form 10-K
for the Year Ended December 31, 1992).
Participation Agreement dated as of August 1, 1992 by and between
NYSERDA and the Company relating to the 1992 EFRBs, Series C (filed as
an Exhibit to the Company's Form 10-K for the Year Ended December 31,
1992).
10(t) Indenture of Trust dated as of August 1, 1992 by and between NYSERDA
and IBJ Schroder Bank and Trust Company, as Trustee, relating to the
1992 EFRBs, Series D (filed as an Exhibit to the Company's Form 10-K
for the Year Ended December 31, 1992).
Participation Agreement dated as of August 1, 1992 by and between
NYSERDA and the Company relating to the 1992 EFRBs, Series D (filed as
an Exhibit to the Company's Form 10-K for the Year Ended December 31,
1992).
10(u) Indenture of Trust dated as of November 1, 1993 by and between NYSERDA
and Chemical Bank, as Trustee, relating to the 1993 EFRBs, Series A
(filed as an Exhibit to the Company's Form 10-K for the Year Ended
December 31, 1993).
Participation Agreement dated as of November 1, 1993 by and between
NYSERDA and the Company relating to the 1993 EFRBs, Series A (filed as
an Exhibit to the Company's Form 10-K for the Year Ended December 31,
1993).
10(v) Indenture of Trust dated as of November 1, 1993 by and between NYSERDA
and Chemical Bank, as Trustee, relating to the 1993 EFRBs, Series B
(filed as an Exhibit to the Company's Form 10-K for the Year Ended
December 31, 1993).
Participation Agreement dated as of November 1, 1993 by and between
NYSERDA and the Company relating to the 1993 EFRBs, Series B (filed as
an Exhibit to the Company's Form 10-K for the Year Ended December 31,
1993).
*10(w) Indenture of Trust dated as of October 1, 1994 by and between NYSERDA
and Chemical Bank, as Trustee, relating to the 1994 EFRBs, Series A.
Participation Agreement dated as of October 1, 1994 by and between
NYSERDA and the Company relating to the 1994 EFRBs, Series A.
10(x) Supplemental Death and Retirement Benefits Plan as amended and
restated effective January 1, 1993 (filed as an Exhibit to the
Company's Form 10-K for the Year Ended December 31, 1993) and related
Trust Agreement, which Trust Agreement was filed as Exhibit 10(q) to
the Company's Form 10-K for the Year Ended December 31, 1990.
*10(y) Executive Agreements and Management Contracts
*(1) Executive Employment Agreement dated as of January 30, 1984 by
and between William J. Catacosinos and the Company, as amended
by amendments dated March 20, 1987 (filed as an Exhibit to the
Company's Form 10-K for the Year Ended December 31, 1986),
December 22, 1989 (filed as an Exhibit to the Company's Form
10-K for the Year Ended December 31, 1989), and December 2,
1991 (filed as an Exhibit to the Company's Form 10-K for the
Year Ended December 31, 1991), which amendment was restated by
an amendment dated as of December 2, 1991; an Executive
Employment Agreement dated as of November 30, 1994.
*(2) Executive Employment Agreement dated as of November
21, 1994 by and between the Company and Theodore A.
Babcock, which agreement is substantially the same as
Executive Employment Agreement by and between the Company and
(1) James T. Flynn, (2) Joseph E. Fontana, (3) Robert
X. Kelleher, (4) John D. Leonard, Jr., (5) Adam M. Madsen,
(6) Kathleen A. Marion, (7) Arthur C. Marquardt, (8) Brian R.
McCaffrey, (9) Joseph W. McDonnell, (10) Anthony Nozzolillo,
(11) Richard Reichler, (12) William G. Schiffmacher, (13)
Robert B. Steger, (14) William E. Steiger, and (15) Edward J.
Youngling.
*(3) Indemnification Agreement by and between the Company
and Theodore A. Babcock dated as of February 23, 1994, which
agreement is substantially the same as Indemnification
Agreement by and between the Company and (1) James T. Flynn
dated as of November 25, 1987, (2) Joseph E. Fontana dated
as of October 20, 1994, (3) Robert X. Kelleher
dated as of November 25, 1987, (4) John D. Leonard, Jr. dated
as of November 25, 1987, (5) Adam M. Madsen dated as of
November 25, 1987, (6) Kathleen A. Marion dated as of May 30,
1990, (7) Arthur C. Marquardt dated as of January 21, 1991,
(8) Brian R. McCaffrey dated as of November 25, 1987, (9)
Joseph W. McDonnell dated as of March 18, 1988, (10) Anthony
Nozzolillo dated as of July 29, 1992, (11) Richard Reichler
dated as of September 30, 1993, (12) William Schiffmacher
dated as of November 25, 1987, (13) Robert B. Steger dated as
of February 20, 1990, (14) William E. Steiger, Jr. dated as of
March 1, 1989, and (15) Edward J. Youngling dated as of
November 4, 1988.
*(4) Indemnification Agreement by and between the Company
and Vicki L. Fuller dated as of January 3, 1994, which
agreement is substantially the same as Indemnification
Agreement by and between the Company and (1) A. James Barnes
dated as of January 31, 1992, (2) George Bugliarello dated
as of May 30, 1990, (3) Renso L. Caporali dated as of April
17, 1992, (4) William J. Catacosinos dated as of
November 19, 1987, (5) Peter O. Crisp dated as of
April 23, 1992, (6) Katherine D. Ortega dated as of April 20,
1993, (7) Basil A. Paterson dated as of November 19, 1987, (8)
Richard L. Schmalensee dated as of
__________________________________
*Filed herewith.
February 8, 1992, (9) George J. Sideris dated as of November
30, 1987, (10) John H. Talmage dated as of November 19, 1987,
and (11) Phyllis A. Vineyard dated as of November 19, 1987.
(5) Indemnification Agreement by and between the Company
and Lionel M. Goldberg dated as of April 20, 1993, (filed as
an Exhibit to the Company's Form 10-K for the Year Ended
December 31, 1993) which agreement is substantially the same
as Indemnification Agreements by and between the Company and
Eben W. Pyne dated as of April 20, 1993, and Winfield E. Fromm
dated as of April 12, 1994.
(6) Long Island Lighting Company Officers' and Directors'
Protective Trust dated as of April 18, 1988 as Amended and
Restated as of September 1, 1994 by and between the Company
and Clarence Goldberg, as Trustee (filed as an Exhibit to the
Company's Form 10-Q for the Quarterly period Ended September
30, 1994).
(7) Long Island Lighting Company's Retirement Plan for Directors
dated as of February 2, 1990 (filed as an Exhibit to the
Company's Form 10-K for the Year Ended December 31, 1989).
(8) Trust Agreement for Officers dated March 20, 1987 by and
between the Company and Clarence Goldberg as Trustee (filed as
an Exhibit to the Company's Form 10-K for the Year Ended
December 31, 1988).
*(9) Consulting Agreement dated as of April 12, 1994 by and
between the Company and Winfield E. Fromm, which agreement is
substantially the same as Consulting Agreements dated as of
April 12, 1994 by and between the Company and Lionel M.
Goldberg and Eben W. Pyne.
*23 Consent of Ernst & Young LLP, Independent Auditors.
*24(a) Powers of Attorney executed by the Directors and Officers of
the Company.
*24(b) Certificate as to Corporate Power of Attorney.
*24(c) Certified copy of Resolution of Board of Directors authorizing
signature pursuant to Power of Attorney.
*27 Financial Data Schedule.
Financial Statements of subsidiary companies accounted for by
the equity method have been omitted because such subsidiaries do not constitute
significant subsidiaries.
(b) Reports on Form 8-K
No reports on Form 8-K were filed in the fourth quarter of
1994.
In its Report on Form 8-K dated February 1, 1995, the Company
reported earnings of $2.15 per common share on revenues of
$3,067,307,000 for the year ended December 31, 1994.
__________________________________
*Filed herewith.
LONG ISLAND LIGHTING COMPANY
SCHEDULE II-VALUATION AND QUALIFYING ACCOUNTS
(THOUSANDS OF DOLLARS)
[Enlarge/Download Table]
-------------------------------------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
-------------------------------------------------------------------------------------------------------------
ADDITIONS
---------------------------
CHARGED
BALANCE AT CHARGED TO TO OTHER BALANCE AT
DESCRIPTION BEGINNING COSTS AND ACCOUNTS- DEDUCTIONS- END OF
OF PERIOD EXPENSES DESCRIBE DESCRIBE PERIOD
-------------------------------------------------------------------------------------------------------------
Year ended December 31,1994
Deducted from asset accounts:
Allowance for doubtful accounts $23,889 $19,542 $20,066 (1) $23,365
Year ended December 31,1993
Deducted from asset accounts:
Allowance for doubtful accounts $24,375 $18,555 $19,041 (1) $23,889
Year ended December 31,1992
Deducted from asset accounts:
Allowance for doubtful accounts $26,935 $16,329 $18,889 (1) $24,375
(1) Uncollectible accounts written off, net of recoveries.
SIGNATURES
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 dates indicated.
Date Signature and Title
---- ---------------------------------
WILLIAM J. CATACOSINOS*
---------------------------------
William J. Catacosinos, Principal
Executive Officer, President and
Chairman of the Board of Directors
JOSEPH E. FONTANA
---------------------------------
Joseph E. Fontana, Controller,
Principal Accounting Officer
A. JAMES BARNES*
---------------------------------
A. James Barnes, Director
GEORGE BUGLIARELLO*
---------------------------------
George Bugliarello, Director
March 14, 1995
RENSO L. CAPORALI*
---------------------------------
Renso L. Caporali, Director
PETER O. CRISP*
---------------------------------
Peter O. Crisp, Director
VICKI L. FULLER*
---------------------------------
Vicki L. Fuller, Director
KATHERINE D. ORTEGA*
---------------------------------
Katherine D. Ortega, Director
BASIL A. PATERSON*
---------------------------------
Basil A. Paterson, Director
RICHARD L. SCHMALENSEE*
---------------------------------
Richard L. Schmalensee, Director
GEORGE J. SIDERIS*
---------------------------------
George J. Sideris, Director
JOHN H. TALMAGE*
---------------------------------
John H. Talmage, Director
PHYLLIS S. VINEYARD*
---------------------------------
Phyllis S. Vineyard, Director
*ANTHONY NOZZOLILLO
---------------------------------
Anthony Nozzolillo (Individually,
as Senior Vice President and Principal
Financial Officer and as
attorney-in-fact for each of
the persons indicated)
March 14, 1995
SIGNATURES
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.
LONG ISLAND LIGHTING COMPANY
Date: March 14, 1995 By: ANTHONY NOZZOLILLO
----------------------------
Anthony Nozzolillo
Principal Financial Officer
Original powers of attorney, authorizing Kathleen A. Marion
and Anthony Nozzolillo, and each of them, to sign this report and any
amendments thereto, as attorney-in-fact for each of the Directors and Officers
of the Company, and a certified copy of the resolution of the Board of
Directors of the Company authorizing said persons and each of them to sign this
report and amendments thereto as attorney-in-fact for any Officers signing on
behalf of the Company, have been, are being filed or will be filed with the
Securities and Exchange Commission.
EXHIBIT INDEX
-------------
Exhibit
No. Description
------- ------------
3(a) Restated Certificate of Incorporation of the Company dated November
11, 1993 (filed as an Exhibit to the Company's Form 10-K for the Year
Ended December 31, 1993.)
(b) By-laws of the Company as amended on May 28, 1991 (filed as an Exhibit
to the Company's Form 10-K for the Year Ended December 31, 1991.)
4(a) General and Refunding Indenture dated as of June 1, 1975 (filed as an
Exhibit to the Company's Form 10-K for the Year Ended December 31,
1991.)
Twenty-seven Supplemental Indentures to the General and Refunding
Indenture dated as of June 1, 1975, as follows:
[Download Table]
Previously Filed As An
Supplemental Indenture Exhibit To The Company's
Number Date Form Date
------ ---- ---- ----
First 06/1/75 10-K 12/31/87
Second 09/1/75 10-K 12/31/87
Third 06/1/76 10-K 12/31/87
Fourth 12/1/76 10-K 12/31/87
Fifth 05/1/77 10-K 12/31/87
Sixth 04/1/78 10-K 12/31/87
Seventh 03/1/79 10-K 12/31/87
Eighth 02/1/80 10-K 12/31/87
Ninth 03/1/81 10-K 12/31/87
Tenth 07/1/81 10-K 12/31/87
Eleventh 07/1/81 10-K 12/31/87
Twelfth 12/1/81 10-K 12/31/87
Thirteenth 12/1/81 10-K 12/31/87
Fourteenth 06/1/82 10-K 12/31/87
Fifteenth 10/1/82 10-K 12/31/87
Sixteenth 04/1/83 10-K 12/31/87
Seventeenth 05/1/83 10-K 12/31/87
Eighteenth 09/1/84 10-K 12/31/87
Nineteenth 10/1/84 10-K 12/31/87
Twentieth 06/1/85 10-K 12/31/87
Twenty-first 04/1/86 10-K 12/31/87
Twenty-second 02/1/91 10-K 12/31/90
Twenty-third 05/1/91 10-K 12/31/91
Twenty-fourth 07/1/91 10-K 12/31/91
[Download Table]
Twenty-fifth 05/1/92 10-K 12/31/92
Twenty-sixth 07/1/92 10-K 12/31/92
*Twenty-seventh 06/1/94 10-K 12/31/94
4(b) Indenture of Mortgage and Deed of Trust dated as of September 1, 1951
(filed as an Exhibit to the Company's Form 10-K for the Year Ended
December 31, 1987.)
Fifty Supplemental Indentures to the Indenture of Mortgage and Deed of
Trust dated as of September 1, 1951, as follows:
[Download Table]
Previously Filed As An
Supplemental Indenture Exhibit To The Company's
Number Date Form Date
------ ---- ---- ----
First 12/1/51 10-K 12/31/87
Second 10/1/52 10-K 12/31/87
Third 09/1/53 10-K 12/31/87
Fourth 12/1/54 10-K 12/31/87
Fifth 11/1/55 10-K 12/31/87
Sixth 12/1/56 10-K 12/31/87
Seventh 05/1/58 10-K 12/31/87
Eighth 07/1/59 10-K 12/31/87
Ninth 08/1/61 10-K 12/31/87
Tenth 04/1/63 10-K 12/31/87
Eleventh 06/1/64 10-K 12/31/87
Twelfth 06/1/65 10-K 12/31/87
Thirteenth 03/1/66 10-K 12/31/87
Fourteenth 04/1/67 10-K 12/31/87
Fifteenth 09/1/69 10-K 12/31/87
Sixteenth 09/1/70 10-K 12/31/87
Seventeenth 04/1/71 10-K 12/31/87
Eighteenth 12/1/71 10-K 12/31/87
Nineteenth 09/1/72 10-K 12/31/87
Twentieth 12/1/73 10-K 12/31/87
Twenty-first 06/1/74 10-K 12/31/87
Twenty-second 11/1/74 10-K 12/31/87
Twenty-third 06/1/75 10-K 12/31/87
Twenty-fourth 09/1/75 10-K 12/31/87
Twenty-fifth 06/1/76 10-K 12/31/87
Twenty-sixth 12/1/76 10-K 12/31/87
Twenty-seventh 05/1/77 10-K 12/31/87
Twenty-eighth 04/1/78 10-K 12/31/87
Twenty-ninth 03/1/79 10-K 12/31/87
Thirtieth 02/1/80 10-K 12/31/87
Thirty-first 03/1/81 10-K 12/31/87
Thirty-second 07/1/81 10-K 12/31/87
Thirty-third 07/1/81 10-K 12/31/87
Thirty-fourth 12/1/81 10-K 12/31/87
__________________________________
*Filed herewith.
[Download Table]
Thirty-fifth 12/1/81 10-K 12/31/87
Thirty-sixth 06/1/82 10-K 12/31/87
Thirty-seventh 10/1/82 10-K 12/31/87
Thirty-eighth 04/1/83 10-K 12/31/87
Thirty-ninth 05/1/83 10-K 12/31/87
Fortieth 02/29/84 10-K 12/31/87
Forty-first 09/1/84 10-K 12/31/87
Forty-second 10/1/84 10-K 12/31/87
Forty-third 06/1/85 10-K 12/31/87
Forty-fourth 04/1/86 10-K 12/31/87
Forty-fifth 02/1/91 10-K 12/31/90
Forty-sixth 05/1/91 10-K 12/31/91
Forty-seventh 07/1/91 10-K 12/31/91
Forty-eighth 05/1/92 10-K 12/31/92
Forty-ninth 07/1/92 10-K 12/31/92
*Fiftieth 06/1/94 10-K 12/31/94
4(c) Debenture Indenture dated as of November 1, 1986 from the Company to
The Connecticut Bank and Trust Company, National Association, as
Trustee (filed as an Exhibit to the Company's Form 10-K for the Year
Ended December 31, 1986).
Seven Supplemental Indentures to the Debenture Indenture dated as of
November 1, 1986, filed as follows:
[Download Table]
Previously Filed As An
Supplemental Indenture Exhibit To The Company's
Number Date Form Date
------ ---- ---- ----
First 11/1/86 10-K 12/31/86
Second 04/1/86 10-K 12/31/89
Third 07/1/86 10-K 12/31/89
Fourth 07/1/92 10-K 12/31/92
Fifth 11/1/92 10-K 12/31/92
Sixth 06/1/93 10-K 12/31/92
Seventh 07/1/93 10-K 12/31/92
__________________________________
*Filed herewith.
4(d) Debenture Indenture dated as of November 1, 1992 from the Company to
Chemical Bank, as Trustee (filed as an Exhibit to the Company's Form
10-K for the Year Ended December 31, 1992).
Four Supplemental Indentures to the Debenture Indenture dated as of
November 1, 1992, filed as follows:
[Download Table]
Previously Filed As An
Supplemental Indenture Exhibit To The Company's
Number Date Form Date
------ ---- ---- ----
First 01/1/93 10-K 12/31/92
Second 03/1/93 10-K 12/31/92
Third 03/1/93 10-K 12/31/92
Fourth 03/1/93 10-K 12/31/92
10(a) Sound Cable Project Facilities and Marketing Agreement dated as of
August 26, 1987 between the Company and the Power Authority of the
State of New York (filed as an Exhibit to the Company's Form 10-K for
the Year Ended December 31, 1987).
10(b) Transmission Agreement by and between the Company and Consolidated
Edison Company of New York, Inc. dated as of March 31, 1989 (filed as
an Exhibit to the Company's Form 10-K for the Year Ended December 31,
1989).
10(c) Contract for the sale of Firm Power and Energy by and between the
Company and the State of New York dated as of April 26, 1989 (filed as
an Exhibit to the Company's Form 10-K for the Year Ended December 31,
1989).
10(d) Capacity Supply Agreement dated as of December 13, 1991 between the
Company and the Power Authority of the State of New York (filed as an
Exhibit to the Company's Form 10-K for the Year Ended December 31,
1991).
10(e) Nine Mile Point Nuclear Station Unit 2 Operating Agreement dated as of
January 1, 1993 by and between the Company, New York State Electric &
Gas Corporation, Rochester Gas and Electric Corporation and Central
Hudson Gas and Electric Corporation (filed as an Exhibit to the
Company's Form 10-K for the Year Ended December 31, 1993).
10(f) Settlement Agreement on Issues Related to Nine Mile Two Nuclear Plant
dated as of June 6, 1990 by and between the Company, the Staff of the
Department of Public Service and others (filed as an Exhibit to the
Company's Form 10-K for the Year Ended December 31, 1990).
10(g) Settlement Agreement -- LILCO Issues dated as of February 28, 1989 by
and between the Company and the State of New York (filed as an Exhibit
to the Company's Form 10-K for the Year Ended December 31, 1988).
10(h) Amended and Restated Asset Transfer Agreement by and between the
Company and the Long Island Power Authority dated as of June 16, 1988
as amended and restated on April 14, 1989 (filed as an Exhibit to the
Company's Form 10-K for the Year Ended December 31, 1989).
10(i) Memorandum of Understanding concerning proposed agreements on power
supply for Long Island dated as of June 16, 1988 by and between the
Company and New York Power Authority as amended May 24, 1989 (filed as
an Exhibit to the Company's Form 10-K for the Year Ended December 31,
1989).
10(j) Rate Moderation Agreement submitted by the staff of the New York
State Public Service Commission on March 16, 1989 and supported by the
Company (filed as an Exhibit to the Company's Form 10-K for the Year
Ended December 31, 1989).
10(k) Site Cooperation and Reimbursement Agreement dated as of January 24,
1990 by and between the Company and Long Island Power Authority (filed
as an Exhibit to the Company's Form 10-K for the Year Ended December
31, 1989).
10(l) Stipulation of settlement of federal Racketeer Influenced and Corrupt
Organizations Act Class Action and False Claims Action dated as of
February 27, 1989 among the attorneys for the Company, the ratepayer
class, the United States of America and the individual defendants
named therein (filed as an Exhibit to the Company's Form 10-K for the
Year Ended December 31, 1988).
10(m) Revolving Credit Agreement dated as of June 27, 1989, between the
Company and the banks and co-agents listed therein, with the Exhibits
thereto (filed as an Exhibit to the Company's Form 10-K for the Year
Ended December 31, 1989) and as amended by the First Amendment dated
as of October 13, 1989 (filed as an Exhibit to the Company's Form 10-K
for the Year Ended December 31, 1990) and as amended by the Second
Amendment dated as of March 5, 1992 and as modified by a Waiver dated
November 5, 1992 (filed as an Exhibit to the Company's Form 10-K for
the Year Ended December 31, 1992).
10(n) Indenture of Trust dated as of December 1, 1989 by and between New
York State Energy Research and Development Authority ("NYSERDA") and
The Connecticut National Bank, as Trustee, relating to the 1989 EFRBs
(filed as an Exhibit to the Company's Form 10-K for the Year Ended
December 31, 1989).
Participation Agreement dated as of December 1, 1989 by and between
NYSERDA and the Company relating to the 1989 EFRBs (filed as an
Exhibit to the Company's Form 10-K for the Year Ended December 31,
1989).
10(o) Indenture of Trust dated as of May 1, 1990 by and between NYSERDA and
The Connecticut National Bank, as Trustee, relating to the 1990 EFRBs
(filed as an Exhibit to the Company's Form 10-K for the Year Ended
December 31, 1990).
Participation Agreement dated as of May 1, 1990 by and between NYSERDA
and the Company relating to the 1990 EFRBs (filed as an Exhibit to the
Company's Form 10-K for the Year Ended December 31, 1990).
10(p) Indenture of Trust dated as of January 1, 1991 by and between NYSERDA
and The Connecticut National Bank, as Trustee, relating to the 1991
EFRBs (filed as an Exhibit to the Company's Form 10-K for the Year
Ended December 31, 1990).
Participation Agreement dated as of January 1, 1991 by and between
NYSERDA and the Company relating to the 1991 EFRBs (filed as an
Exhibit to the Company's Form 10-K for the Year Ended December 31,
1990).
10(q) Indenture of Trust dated as of February 1, 1992 by and between NYSERDA
and IBJ Schroder Bank and Trust Company, as Trustee, relating to the
1992 EFRBs, Series A (filed as an Exhibit to the Company's Form 10-K
for the Year Ended December 31, 1991).
Participation Agreement dated as of February 1, 1992 by and between
NYSERDA and the Company relating to the 1992 EFRBs, Series A (filed as
an Exhibit to the Company's Form 10-K for the Year Ended December 31,
1991).
10(r) Indenture of Trust dated as of February 1, 1992 by and between NYSERDA
and IBJ Schroder Bank and Trust Company, as Trustee, relating to the
1992 EFRBs, Series B (filed as an Exhibit to the Company's Form 10-K
for the Year Ended December 31, 1991).
Participation Agreement dated as of February 1, 1992 by and between
NYSERDA and the Company relating to the 1992 EFRBs, Series B (filed as
an Exhibit to the Company's Form 10-K for the Year Ended December 31,
1991).
10(s) Indenture of Trust dated as of August 1, 1992 by and between NYSERDA
and IBJ Schroder Bank and Trust Company, as Trustee, relating to the
1992 EFRBs, Series C (filed as an Exhibit to the Company's Form 10-K
for the Year Ended December 31, 1992).
Participation Agreement dated as of August 1, 1992 by and between
NYSERDA and the Company relating to the 1992 EFRBs, Series C (filed as
an Exhibit to the Company's Form 10-K for the Year Ended December 31,
1992).
10(t) Indenture of Trust dated as of August 1, 1992 by and between NYSERDA
and IBJ Schroder Bank and Trust Company, as Trustee, relating to the
1992 EFRBs, Series D (filed as an Exhibit to the Company's Form 10-K
for the Year Ended December 31, 1992).
Participation Agreement dated as of August 1, 1992 by and between
NYSERDA and the Company relating to the 1992 EFRBs, Series D (filed as
an Exhibit to the Company's Form 10-K for the Year Ended December 31,
1992).
10(u) Indenture of Trust dated as of November 1, 1993 by and between NYSERDA
and Chemical Bank, as Trustee, relating to the 1993 EFRBs, Series A
(filed as an Exhibit to the Company's Form 10-K for the Year Ended
December 31, 1993).
Participation Agreement dated as of November 1, 1993 by and between
NYSERDA and the Company relating to the 1993 EFRBs, Series A (filed as
an Exhibit to the Company's Form 10-K for the Year Ended December 31,
1993).
10(v) Indenture of Trust dated as of November 1, 1993 by and between NYSERDA
and Chemical Bank, as Trustee, relating to the 1993 EFRBs, Series B
(filed as an Exhibit to the Company's Form 10-K for the Year Ended
December 31, 1993).
Participation Agreement dated as of November 1, 1993 by and between
NYSERDA and the Company relating to the 1993 EFRBs, Series B (filed as
an Exhibit to the Company's Form 10-K for the Year Ended December 31,
1993).
*10(w) Indenture of Trust dated as of October 1, 1994 by and between NYSERDA
and Chemical Bank, as Trustee, relating to the 1994 EFRBs, Series A.
Participation Agreement dated as of October 1, 1994 by and between
NYSERDA and the Company relating to the 1994 EFRBs, Series A.
10(x) Supplemental Death and Retirement Benefits Plan as amended and
restated effective January 1, 1993 (filed as an Exhibit to the
Company's Form 10-K for the Year Ended December 31, 1993) and related
Trust Agreement, which Trust Agreement was filed as Exhibit 10(q) to
the Company's Form 10-K for the Year Ended December 31, 1990.
*10(y) Executive Agreements and Management Contracts
*(1) Executive Employment Agreement dated as of January 30, 1984 by
and between William J. Catacosinos and the Company, as amended
by amendments dated March 20, 1987 (filed as an Exhibit to the
Company's Form 10-K for the Year Ended December 31, 1986),
December 22, 1989 (filed as an Exhibit to the Company's Form
10-K for the Year Ended December 31, 1989), and December 2,
1991 (filed as an Exhibit to the Company's Form 10-K for the
Year Ended December 31, 1991), which amendment was restated by
an amendment dated as of December 2, 1991; an Executive
Employment Agreement dated as of November 30, 1994.
*(2) Executive Employment Agreement dated as of November
21, 1994 by and between the Company and Theodore A.
Babcock, which agreement is substantially the same as
Executive Employment Agreement by and between the Company and
(1) James T. Flynn, (2) Joseph E. Fontana, (3) Robert
X. Kelleher, (4) John D. Leonard, Jr., (5) Adam M. Madsen,
(6) Kathleen A. Marion, (7) Arthur C. Marquardt, (8) Brian R.
McCaffrey, (9) Joseph W. McDonnell, (10) Anthony Nozzolillo,
(11) Richard Reichler, (12) William G. Schiffmacher, (13)
Robert B. Steger, (14) William E. Steiger, and (15) Edward J.
Youngling.
*(3) Indemnification Agreement by and between the Company
and Theodore A. Babcock dated as of February 23, 1994, which
agreement is substantially the same as Indemnification
Agreement by and between the Company and (1) James T. Flynn
dated as of November 25, 1987, (2) Joseph E. Fontana dated
as of October 20, 1994, (3) Robert X. Kelleher
dated as of November 25, 1987, (4) John D. Leonard, Jr. dated
as of November 25, 1987, (5) Adam M. Madsen dated as of
November 25, 1987, (6) Kathleen A. Marion dated as of May 30,
1990, (7) Arthur C. Marquardt dated as of January 21, 1991,
(8) Brian R. McCaffrey dated as of November 25, 1987, (9)
Joseph W. McDonnell dated as of March 18, 1988, (10) Anthony
Nozzolillo dated as of July 29, 1992, (11) Richard Reichler
dated as of September 30, 1993, (12) William Schiffmacher
dated as of November 25, 1987, (13) Robert B. Steger dated as
of February 20, 1990, (14) William E. Steiger, Jr. dated as of
March 1, 1989, and (15) Edward J. Youngling dated as of
November 4, 1988.
*(4) Indemnification Agreement by and between the Company
and Vicki L. Fuller dated as of January 3, 1994, which
agreement is substantially the same as Indemnification
Agreement by and between the Company and (1) A. James Barnes
dated as of January 31, 1992, (2) George Bugliarello dated
as of May 30, 1990, (3) Renso L. Caporali dated as of April
17, 1992, (4) William J. Catacosinos dated as of
November 19, 1987, (5) Peter O. Crisp dated as of
April 23, 1992, (6) Katherine D. Ortega dated as of April 20,
1993, (7) Basil A. Paterson dated as of November 19, 1987, (8)
Richard L. Schmalensee dated as of
__________________________________
*Filed herewith.
February 8, 1992, (9) George J. Sideris dated as of November
30, 1987, (10) John H. Talmage dated as of November 19, 1987,
and (11) Phyllis A. Vineyard dated as of November 19, 1987.
(5) Indemnification Agreement by and between the Company
and Lionel M. Goldberg dated as of April 20, 1993, (filed as
an Exhibit to the Company's Form 10-K for the Year Ended
December 31, 1993) which agreement is substantially the same
as Indemnification Agreements by and between the Company and
Eben W. Pyne dated as of April 20, 1993, and Winfield E. Fromm
dated as of April 12, 1994.
(6) Long Island Lighting Company Officers' and Directors'
Protective Trust dated as of April 18, 1988 as Amended and
Restated as of September 1, 1994 by and between the Company
and Clarence Goldberg, as Trustee (filed as an Exhibit to the
Company's Form 10-Q for the Quarterly period Ended September
30, 1994).
(7) Long Island Lighting Company's Retirement Plan for Directors
dated as of February 2, 1990 (filed as an Exhibit to the
Company's Form 10-K for the Year Ended December 31, 1989).
(8) Trust Agreement for Officers dated March 20, 1987 by and
between the Company and Clarence Goldberg as Trustee (filed as
an Exhibit to the Company's Form 10-K for the Year Ended
December 31, 1988).
*(9) Consulting Agreement dated as of April 12, 1994 by and
between the Company and Winfield E. Fromm, which agreement is
substantially the same as Consulting Agreements dated as of
April 12, 1994 by and between the Company and Lionel M.
Goldberg and Eben W. Pyne.
*23 Consent of Ernst & Young LLP, Independent Auditors.
*24(a) Powers of Attorney executed by the Directors and Officers of
the Company.
*24(b) Certificate as to Corporate Power of Attorney.
*24(c) Certified copy of Resolution of Board of Directors authorizing
signature pursuant to Power of Attorney.
*27 Financial Data Schedule.
Financial Statements of subsidiary companies accounted for by
the equity method have been omitted because such subsidiaries do not constitute
significant subsidiaries.
(b) Reports on Form 8-K
No reports on Form 8-K were filed in the fourth quarter of
1994.
In its Report on Form 8-K dated February 1, 1995, the Company
reported earnings of $2.15 per common share on revenues of
$3,067,307,000 for the year ended December 31, 1994.
__________________________________
*Filed herewith.
Dates Referenced Herein and Documents Incorporated by Reference
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